UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ______________________________________________________________

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission File No. 001-11155

  ______________________________________________________________

WESTMORELAND COAL COMPANY

(Exact name of registrant as specified in its charter)

Delaware	23-1128670
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
9540 South Maroon Circle, Suite 200 Englewood, CO	80112
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (855) 922-6463

Securities registered pursuant to Section 12(b) of the Act:

 ______________________________________________________________­

Title of Each Class	Name of Exchange on Which Registered
Common Stock, par value $2.50 per share	NASDAQ Global Market
Depositary Shares, each representing one-quarter of a share of Series A Convertible Exchangeable Preferred Stock

Securities registered pursuant to Section 12(g) of the Act:

  ______________________________________________________________

Series A Convertible Exchangeable Preferred Stock, par value $1.00 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨     No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨     No   x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company.)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of voting common stock held by non-affiliates as of June 30, 2014 was $133,270,554.

There were 17,752,214 shares outstanding of the registrant’s common stock, $2.50 par value per share (the registrant’s only class of common stock), as of March 3, 2015.

  ______________________________________________________________

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement to be filed within 120 days after December 31, 2014, in connection with the Company's 2014 Annual Meeting of Stockholders scheduled to be held on May 19, 2015, are incorporated by reference into Part III of this Annual Report on Form 10-K.

WESTMORELAND COAL COMPANY

FORM 10-K

ANNUAL REPORT

TABLE OF CONTENTS

Item		Page
	PART I
1	Business	5
1A	Risk Factors	33
1B	Unresolved Staff Comments	53
2	Properties	53
3	Legal Proceedings	53
4	Mine Safety Disclosure	53
	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
6	Selected Financial Data	56
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59
7A	Quantitative and Qualitative Disclosures about Market Risk	74
8	Financial Statements and Supplementary Data	76
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	128
9A	Controls and Procedures	128
	PART III
10	Directors, Executive Officers and Corporate Governance	130
11	Executive Compensation	130
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	130
13	Certain Relationships and Related Transactions, and Director Independence	130
14	Principal Accountant Fees and Services	130
	PART IV
15	Exhibits and Financial Statement Schedules	131
Signatures		132

2

Cautionary Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements.” Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements we make throughout this report regarding recent acquisitions and their anticipated effects on us, and statements in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Anticipated Variances Between 2014 and 2015 and Related Uncertainties” regarding factors that may cause our results of operation in future periods to differ from our expectations.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are statements neither of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements include political, economic, business, competitive, market, weather and regulatory conditions and the following:

• Our ability to effectively manage Westmoreland Resource Partners, LP;

• Our efforts to effectively integrate the operations we acquired in the Canadian Acquisition with our existing business and our ability to manage our expanded operations following the acquisition;

• Our ability to realize growth opportunities and cost synergies as a result of the addition of our Canadian Operations;

• Our substantial level of indebtedness and our ability to adhere to financial covenants related to our borrowing arrangements;

• The ability of our hedging arrangement with respect to our Roanoke Valley Power Facility to generate free cash flow due to the fully hedged position through March 2019;

• Changes in our post-retirement medical benefit and pension obligations and the impact of the recently enacted healthcare legislation on our employee health benefit costs;

• Inaccuracies in our estimates of our coal reserves;

• The effect of consummating financing, acquisition or disposition transactions;

•  Our potential inability to expand or continue current coal operations due to limitations in obtaining bonding capacity for new mining permits, and/or increases in our mining costs as a result of increased bonding expenses;

• The effect of prolonged maintenance or unplanned outages at our operations or those of our major power generating customers;

• The inability to control costs, recognize favorable tax credits and/or receive adequate train traffic at our open market mine operations;

• Competition within our industry and with producers of competing energy sources;

• Our relationships with, and other conditions affecting, our customers;

• The availability and costs of key supplies or commodities, such as diesel fuel, steel and explosives;

• Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;

• The effect of legal and administrative proceedings, settlements, investigations and claims, including any related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage;

• Existing and future legislation and regulation affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases ("GHGs");

• The effect of the Environmental Protection Agency’s and Canadian and provincial governments’ inquiries and regulations affecting operations of the power plants to which we provide coal; and

• Other factors that are described in “Risk Factors” in this report and under the heading “Risk Factors” found in our other reports filed with the Securities and Exchange Commission (“SEC”), including our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.

3

Unless otherwise specified, the forward-looking statements in this report speak as of the filing date of this report. Factors or events that could cause our actual results to differ may emerge from time-to-time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether because of new information, future developments or otherwise, except as may be required by law.

Reserve engineering is a process of estimating underground accumulations of coal that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of mining, testing and production activities may justify revision of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development of reserves. Accordingly, reserve estimates may differ from the quantities of coal that are ultimately recovered.

4

PART I

The words “we,” “our,” “the Company,” or “Westmoreland,” as used in this report, refer to Westmoreland Coal Company and its subsidiaries.

ITEM 1 — BUSINESS.

Overview

Westmoreland Coal Company began mining in Westmoreland County, Pennsylvania in 1854 as a Pennsylvania corporation. In 1910, we incorporated in Delaware and continued our focus on coal operations in Pennsylvania and the Appalachian Basin. We moved our headquarters from Philadelphia, Pennsylvania to Colorado Springs in 1995 and relocated the headquarters to Englewood, Colorado in November 2011.

Today, Westmoreland Coal Company is an energy company employing approximately 3,440 employees. We conduct our operations through our subsidiaries and our principal sources of cash are distributions from our operating subsidiaries. Our operations include 13 wholly-owned coal mines in the U.S. and Canada, a char production facility, a 50% stake in an activated carbon plant, and two coal-fired power generation units. We also own the general partner of, and 79% of the total equity interest in, Westmoreland Resource Partners, LP (“WMLP”), a publicly traded limited partnership that owns and operates five mining complexes in Northern Appalachia. We sold 44.8 million tons of coal in 2014.

We classify our business into six segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage and Corporate. Our principal operating segments are our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments. Our two non-operating segments are our heritage and corporate segments. Our heritage segment primarily includes the costs of benefits we provide to former mining operation employees and our corporate segment consists primarily of corporate administrative expenses.

5

The following chart provides an overview of the current operating subsidiaries that comprise our coal and power segments and our relationship to each of them. The entities shaded in dark grey represent the "Restricted Group", and the unshaded entities represent the "Unrestricted Group" for the purposes of certain of our debt agreements and instruments, described in further detail under the heading "2014 Transactions - Debt Restructuring" below, in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources, and also at Note 6 to our consolidated financial statements:

We produce and sell thermal coal primarily to investment grade utility customers under long-term cost-protected contracts, as well as to industrial customers and barbeque briquettes manufacturers. Our focus is on mine locations where we can employ dragline surface mining methods. We have extensive operational experience in dragline surface mining and this mining method has historically had predictable and consistent costs and production rates. In addition, we focus on mine locations that allow us to take advantage of close customer proximity through mine-mouth power plants and strategically located rail transportation, with the goal of being the low-cost supplier of choice to the customers that we serve. We believe this business model has contributed to the stability of our cash flows and results of operations.

Our U.S. coal operations are located in Montana, Wyoming, North Dakota and Texas. Our Canadian coal operations are located in Alberta and Saskatchewan. We also operate two coal-fired power generating units in North Carolina with a total capacity of approximately 230 megawatts.

As of December 31, 2014, our long-term debt consisted of (i) $350.0 million in principal amount of our 8.75% Senior Secured Notes due 2022 and (ii) a $350 million term loan maturing in 2020, which was increased to $425 million in January 2015. We incorporate by reference the information regarding the revenues, operating income and total assets of each of our

6

segments for the years ended December 31, 2014, 2013 and 2012 contained in Note 17 - Business Segment Information to our consolidated financial statements.

2014 Transactions

Canadian Acquisition

On April 28, 2014, we acquired (the “Canadian Acquisition”) Prairie Mines & Royalty ULC (also referred to as Prairie or PMRU) and Coal Valley Resources Inc. (also referred to as Mountain or CVRI). PMRU and CVRI form the basis of our Canadian operations and together are referred to as our “Canadian Subsidiaries” or “Canadian Operations.” The Canadian Acquisition included six producing thermal coal mines in the Canadian provinces of Alberta and Saskatchewan, a char production facility, and a 50% interest in an activated carbon plant. The purchase consideration included a $282.8 million initial cash payment made on April 28, 2014, a cash payment for a working capital adjustment of $39.8 million made on June 25, 2014, and assumed liabilities of $421.3 million.

In connection with the Canadian Acquisition: (i) we issued an additional $425.0 million of 10.75% Notes which were subsequently repurchased, as described under “Debt Restructuring” below; (ii) we increased our revolving credit facility to $60 million, which was subsequently amended as described under “Debt Restructuring” below; and (iii) Westmoreland Mining LLC, ("WML") a wholly owned subsidiary of Westmoreland, redeemed its outstanding 8.02% senior secured notes due 2018 and terminated its revolving credit facility.

Equity Offering

On July 16, 2014, we completed a public offering of 1,684,507 shares of common stock at $35.50 per share for gross proceeds of $59.8 million. Brokerage fees were $1.775 per share or $3.0 million and other fees associated with the offering were $0.3 million.

Sale of Port Access

On August 7, 2014, CVRI entered into an agreement (the “Cloud Peak Agreement”) with Cloud Peak Energy Logistics LLC (“CPE Logistics”), a wholly-owned subsidiary of Cloud Peak Energy Inc., pursuant to which CPE Logistics paid $37 million to CVRI for CVRI to voluntarily terminate its throughput agreement with Westshore Terminals Limited Partnership (“Westshore”) at its Robert Banks, British Columbia, Canada, export terminal. In connection with the Cloud Peak Agreement, CVRI entered into a related agreement with Westshore to voluntarily terminate its throughput capacity effective as of December 31, 2014. Beginning in January 2015, CVRI began shipping all of its Coal Valley mine export tonnage through Ridley Terminals located in Prince Rupert, British Columbia, Canada.

Debt Restructuring

On December 16, 2014, we entered into several transactions aimed at reorganizing our debt in order to optimize our capital structure and facilitate the transactions described below under "WMLP Transactions". Each of the debt restructuring transactions is summarized below and described in greater detail in Note 6 to our consolidated financial statements.

Tender Offer. We completed a tender offer for the repurchase of our 10.75% Senior Secured Notes due 2018 (the “10.75% Notes”). An aggregate of $664,960,000, representing 98.44% of the principal amount of the 10.75% Notes, was tendered. In connection with the closing of the tender offer, we issued a notice of redemption to holders of remaining 10.75% Notes and redeemed such notes on December 16, 2014. We funded the consideration for the tender offer using proceeds from the 8.75% Notes offering and the Term Loan described below, as well as available cash on hand.

8.75% Notes Offering. We completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes due 2022 (the “8.75% Notes”). The 8.75% Notes were issued pursuant to an indenture (the “Indenture”), by and among the Company, certain subsidiary guarantors named therein, and U.S. Bank National Association, as trustee and notes collateral agent. The 8.75% Notes mature on January 1, 2022, with interest payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015.

Term Loan. We borrowed $350.0 million pursuant to a term loan credit agreement with the lenders from time to time party thereto and Bank of Montreal, as administrative agent (the “Term Loan Credit Agreement”), and subsequently increased the principal amount of borrowing to $425.0 million in January 2015 (the “Term Loan”). We may elect to have borrowings under the Term Loan bear interest at a per annum rate of (i) one, two-, three- or six-month LIBOR plus 6.50% or (ii) a base rate

7

(determined with reference to the highest of the prime rate, the Federal Funds Rate plus 0.50%, and one-month LIBOR plus 1.00%) plus 5.50%. The Term Loan matures on December 16, 2020.

Revolving Credit Facility. We amended and restated our revolving credit facility with The PrivateBank and Trust Company (the “Revolving Credit Facility Agreement”) to permit us to borrow up to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility made available to our US borrowers and a $20.0 million sub-facility made available to our Canadian borrowers (together, the “Revolving Credit Facility”). At December 31, 2014, availability under the Revolving Credit Facility was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit.

Please see Note 6 to our consolidated financial statements for more information regarding our debt restructuring.

WMLP Transactions

On December 31, 2014, we completed the acquisition of the general partner of WMLP and the contribution of certain royalty-bearing coal reserves at our Kemmerer Mine to WMLP in exchange for common units representing limited partner interests in WMLP.We paid a total of $33.5 million in cash to acquire the general partner and received 4,512,500 common units of WMLP (on a post-split basis following the 12-to-1 reverse split of WMLP’s units that occurred in connection with the closing of our acquisition of the general partner) as consideration for the contribution. Our ownership in WMLP represents 79% of the outstanding equity interests in WMLP, following the 25% unit dividend to unit holders that occurred on January 30, 2015. The closing of these transactions (collectively, the "WMLP Transactions") followed the restructuring of both Westmoreland’s and WMLP’s debt arrangements, as well as the approval by WMLP’s public unitholders of the contribution and WMLP’s restructuring through certain amendments to its partnership agreement.

In connection with the closing, WMLP’s name was changed from Oxford Resource Partners, LP to Westmoreland Resource Partners, LP and the name of the general partner entity was changed from Oxford Resources GP, LLC to Westmoreland Resources GP, LLC (the “GP”). The common units of WMLP trade on the New York Stock Exchange (“NYSE”) under the symbol “WMLP.” WMLP will continue to operate as a stand-alone, publicly traded master limited partnership. WMLP and its subsidiaries are designated as “unrestricted subsidiaries” under the Term Loan Credit Agreement, the Indenture and the Revolving Credit Facility Agreement. As a result, WMLP and its subsidiaries are not subject to any of the restrictive covenants under such instruments, nor are any of their assets pledged as collateral with respect to such instruments.

Going forward, we expect WMLP to provide us with a platform to implement a value-creating “drop-down” strategy pursuant to which we intend to periodically contribute certain U.S. and Canadian coal assets to WMLP in exchange for a combination of cash and additional limited partner interests. We intend to complete the first such drop-down transaction in 2015. Further, as the general partner of WMLP, we expect to optimize its operations and improve its financial performance. We expect the combination of contributions of assets and improved WMLP operations to result in the continued payment of quarterly distributions to WMLP unitholders, including us, as well as increasing future payments to us as a result of incentive distribution rights to which we are entitled as WMLP’s general partner.

Recent Developments

Buckingham Acquisition

On January 1, 2015, we acquired Buckingham Coal Company, LLC (“Buckingham”), an Ohio-based coal supplier, for a total cash purchase price of $34.0 million, subject to customary post-closing adjustments. Separately, an affiliate of Westmoreland entered into a five-year coal supply agreement with AEP Generation Resources Inc. (“AEP”), which includes an obligation to purchase a minimum of 5.5 million tons of coal. In connection with this acquisition, we amended the Term Loan to increase the principal amount by $75.0 million, for an aggregate principal Term Loan amount of $425.0 million.

Buckingham conducts underground room and pillar mining operations in Ohio. Buckingham is strategically located near WMLP's New Lexington complex, which has access to the Norfolk Southern rail system and a state-of-the-art preparation plant strategically located for efficient rail and river transportation for both Buckingham and WMLP coal. We expect Buckingham's proximity to WMLP’s New Lexington complex to allow for substitute tonnage to be supplied by WMLP to AEP when it is economically advantageous to do so.

8

The following map shows our current operations, including the operations under our control following our acquisition of (i) the GP and approximately 79% of the total equity interest in WMLP and (ii) Buckingham:

U.S. and Canada Coal Segments

General

Our Coal - U.S. and Coal - Canada Segments focus on niche coal markets where we take advantage of customer proximity and strategically located rail transportation. We sell substantially all of the coal that we produce to plants that generate electricity. The locations of our mines and coal reserves in close proximity to our customers reduces transportation costs and, we believe, provides us with a significant competitive advantage with respect to retention of those customers. Ten of our mines are directly adjacent to the customer’s property, with economical delivery methods that include, in several cases, conveyor belt delivery systems linked to the customer’s facilities. Several customers have designed and built power plant facilities for the chemical specifications of the coal we supply. We typically enter into long-term, cost-protected supply contracts with our customers that range from approximately one to 40 years. Our current coal sales contracts have a weighted average remaining term of 11 years. For the twelve months ended December 31, 2014, substantially all of our tons of coal sold were sold under long-term contracts. We employ a rigorous capital spending and maintenance philosophy and believe our equipment is well maintained.

Properties

Across all our coal operating segments (Coal - U.S., Coal - Canada and Coal - WMLP), we owned or controlled an estimated 1,265.2 million tons of total proven or probable coal reserves as of December 31, 2014, including 76.1 million tons of proven or probable coal reserves held by WMLP, of which we are general partner and owner of 79% of the total outstanding equity.

Substantially all of our properties and assets in the Coal - U.S. Segment and Coal - Canada Segment are encumbered by liens securing our and our subsidiaries’ outstanding indebtedness. Specifically, the holders of the 8.75% Notes and the lenders under the Term Loan hold first priority liens, on a pari passu basis, on substantially all of our and our wholly owned subsidiaries’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens). In addition, borrowings under the Revolving Credit Facility are secured by first priority liens on our and our wholly owned subsidiaries accounts receivable, inventory and certain other specified assets. The assets of WMLP, of which we are the general partner and owner of 79% of the total outstanding equity interests, are encumbered by separate liens securing the indebtedness of WMLP and its subsidiaries and are not part of the collateral with respect to the Indenture, the Term Loan or the Revolving Credit Facility.

9

The following table provides information about mines we owned or controlled as of December 31, 2014:

	Coal - U.S.	Coal - Canada	Coal - WMLP(2)	Total
	(In thousands of tons)
Coal reserves:(1)
Proven	447,801	606,941	67,720	1,122,462
Probable	24,383	109,996	8,396	142,775
Total proven and probable reserves	472,184	716,937	76,116	1,265,237
Permitted reserves	221,164	597,025	39,184	857,373
2014 production	28,118	15,729	5,598	49,445

____________________

(1) The SEC Industry Guide 7 defines reserves as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

(2) Represents total reserve information for WMLP, of which we are the general partner and owner of 79% of the total outstanding equity interests.

10

The following table provides summary information regarding our principal mining operations as of December 31, 2014:

Mining Operation	Prior  Operator	Manner of Transport	Machinery	Tons Sold (In thousands)			Total Cost of Property, Plant and Equipment ($ in millions)		Employees/Labor Relations(1)	Coal Seam
				2012	2013	2014
Coal - U.S. Segment
MONTANA
Rosebud	Entech, Inc., a subsidiary of Montana Power, Purchased 2001	Ÿ  Conveyor     belt Ÿ  BNSF Rail  Ÿ  Truck	Ÿ  4 draglines  Ÿ  Load-out      facility	8,018	8,234	9,018	$	181.4	369 employees; 287  represented  by Local 400 of the IUOE	Ÿ  Rosebud
Absaloka	Washington Group International, Inc. as contract operator, Ended contract in 2007	Ÿ  BNSF Rail  Ÿ  Truck	Ÿ  1 dragline  Ÿ  Load-out     facility	2,714	4,168	6,557	$	163.7	188 employees; 155 represented by Local 400 of the IUOE	Ÿ  Rosebud-McKay
Savage	Knife River Corporation, a subsidiary of MDU Resources Group, Inc., Purchased 2001	Ÿ  Truck	Ÿ  1 dragline	298	350	332	$	9.3	12 employees; 10 represented by Local 400 of the IUOE	Ÿ  Pust
TEXAS
Jewett	Entech, Inc., a subsidiary of Montana Power, Purchased 2001	Ÿ  Conveyor     belt	Ÿ  4 draglines	4,201	5,015	5,255	$	31.9	324 employees	Ÿ  Wilcox     Group
NORTH DAKOTA
Beulah	Knife River Corporation, a subsidiary of MDU Resources Group, Inc., Purchased 2001	Ÿ  Conveyor     belt Ÿ  BNSF Rail	Ÿ  1 dragline Ÿ  Load-out     facility	2,267	2,521	2,731	$	66.5	147 employees; 120 represented by Local 1101 of the UMWA	Ÿ  Schoolhouse Ÿ  Beulah-Zap
WYOMING
Kemmerer	Chevron Mining Inc., Purchased 2012	Ÿ  Conveyor     belt Ÿ  Rail Ÿ  Truck	Ÿ  Truck and     shovel	4,247	4,639	4,399	$	137.2	297 employees; 236 represented by Local 1307 of the UMWA	Ÿ  Adaville Series
TOTALS Coal - U.S. Segment
				21,745	24,927	28,292	$	590.0	1,337 employees (808 union)

11

Mining Operation	Prior  Operator	Manner of Transport	Machinery	Tons Sold (In thousands) (2)			Total Cost of Property, Plant and Equipment ($ in millions)		Employees/Labor Relations(1)	Coal Seam
				2012	2013	2014
Coal - Canada Segment
Alberta
Paintearth	Sherritt International Corporation	Ÿ  Haul Trucks	Ÿ  2 draglines Ÿ  Cat 789 (4), EX 2600 shovel, haulers			1,950	$	24.8	125 Employees; 104 Represented by IUOE	Ÿ  Battle River, Paintearth
Genesee	Sherritt International Corporation	Ÿ  Haul Trucks	Ÿ  2 draglines Ÿ  Cat 789, Komatsu 830E, P&H 4100, haulers			3,621	$	53.1	129 employees	Ÿ  Ardley Coal Zone
Sheerness	Sherritt International Corporation	Ÿ  Haul Trucks	Ÿ  2 draglines Ÿ  Cat 993 FEL, Cat 776 Haulers			2,490	$	36.6	104 Employees; 86 Represented by IUOE	Ÿ  Sunnynook, Sheerness
Coal Valley	Sherritt International Corporation	Ÿ  Rail	Ÿ  2 draglines Ÿ  Shovels and End Dump Trucks			2,022	$	39.6	316 Employees; 256 Represented by IOUE	Ÿ  Val D'Or, Arbour, Mynheer
Saskatchewan
Poplar River	Sherritt International Corporation	Ÿ  Rail	Ÿ  2 draglines Ÿ  FEL, 195B shovel, tractor trailer haulers			2,617	$	37.3	158 Employees; 131 Represented by IBEW	Ÿ  Willow Bunch
Estevan	Sherritt International Corporation	Ÿ  Haul Trucks	Ÿ  6 draglines Ÿ  FEL and tractor trailer haulers			3,705	$	123.8	359 Employees; 291 Represented by UMWA	Ÿ  Souris River, Roche Percee, Estevan
TOTALS Coal - Canada Segment
						16,405	$	315.2	1191 employees (868 union)

____________________

(1) These numbers do not include employees located in our corporate head office in Denver, our Canadian corporate office or at mine sites other than those listed, which together include 101 non-union employees. As of December 31, 2014, 1,676 employees, or approximately 64% of our total employees, were represented by collective bargaining agreements. The labor agreements at the Savage Mine, Kemmerer Mine, Rosebud Mine and Beulah Mine expire in 2016, 2018, 2019 and 2020, respectively. The labor agreement at our Absaloka mine, which covers approximately 6% of our total workforce, expires on May 31, 2015. The labor agreements at the Sheerness, Paintearth, Poplar River and Coal Valley mines expire in, 2017, 2017, 2016 and 2019 respectively. The labor agreement at our Estevan mine, which represents approximately 11% of our total workforce, will expire on June 30, 2015.

(2) We closed the transaction for the purchase of the Alberta and Saskatchewan mines on April 28, 2014. The numbers reported for those mines for 2014 are reported for the 8 month period from April 28, 2014 to December 31, 2014. Historical tonnage for 2012 and 2013 is not applicable to the Canadian mines.

12

Coal - U.S. Segment Properties

Our Coal - U.S. Segment is composed of our wholly owned mines located in the United States. Mines in our Coal - U.S. Segment control coal reserves and deposits through long-term leases. Our Coal - U.S. Segment owned or controlled an estimated 472.2 million tons of total proven or probable coal reserves as of December 31, 2014. Montana, Wyoming, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining. Mines in our Coal - U.S. Segment have chosen to permit coal reserves on an incremental basis and given the current rates of mining and demand, have sufficient permitted coal to meet production for the periods shown in the table below. We secure all of our final reclamation obligations by reclamation bonds as required by the respective state agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.

The following table provides information about mines in our Coal - U.S. Segmentas of December 31, 2014:

	Absaloka Mine	Rosebud Mine	Jewett Mine	Beulah Mine	Savage Mine	Kemmerer Mine	Total
Owned by	Westmoreland Resources, Inc.	Western Energy Company	Texas Westmoreland Coal Co.	Dakota Westmoreland Corporation	Westmoreland Savage Corporation	Westmoreland Kemmerer, Inc.
Location	Big Horn County, MT	Rosebud and Treasure Counties, MT	Leon,  Freestone and Limestone Counties, TX	Mercer and Oliver Counties, ND	Richland County, MT	Lincoln County, WY
Coal reserves (thousands of tons) Proven	41,791	269,455	24,108	22,504	4,513	85,430	447,801
Probable	—	—	—	15,516	—	8,867	24,383
Total proven and probable reserves (thousands of tons)	41,791	269,455	24,108	38,020	4,513	94,297	472,184
Permitted reserves (thousands of tons)	41,791	100,678	24,108	14,497	4,513	35,577	221,164
2014 production (thousands of tons)	6,612	8,754	5,255	2,764	334	4,399	28,118
Estimated life of permitted reserves(1)	2020	2024	2021	2014	2028	2025
Lessor	Ÿ  Crow Tribe Ÿ  Private parties	Ÿ  Federal Government Ÿ  State of MT Ÿ  Great Northern Properties	Ÿ  Private parties	Ÿ  Private parties Ÿ  State of ND Ÿ  Federal Government	Ÿ  Federal Government Ÿ  Private parties	Ÿ  Federal Government Ÿ  Private parties
Lease term	Through exhaustion	Varies	Varies	Varies	Varies	Varies
Current production capacity (thousands of tons)	7,500	13,300	7,000	3,400	400	7,000
Coal type	Sub-bituminous	Sub-bituminous	Lignite	Lignite	Lignite	Sub-bituminous
Major customers	Ÿ  Xcel Energy Ÿ  Western Fuels Assoc. Ÿ  Midwest Energy Ÿ  Rocky Mountain Power Ÿ  Trans Alta	Ÿ  Colstrip 1&2 owners Ÿ  Colstrip 3&4 owners	Ÿ  NRG Texas Power LLC	Ÿ  Otter Tail Ÿ  MDU Ÿ  Northern Municipal Power Agency Ÿ  Northwestern Energy	Ÿ  MDU Ÿ  Sidney Sugars	Ÿ  PacifiCorp Ÿ  Various industrial customers
Delivery method	Rail / Truck	Truck / Rail / Conveyor	Conveyor	Conveyor /  Rail	Truck	Conveyor/  Rail/ Truck
Approx. heat content (BTU/lb.)(2)	8,509	8,455	6,631	7,090	6,472	9,853
Approx. sulfur content (%)(3)	0.64	0.69	0.91	0.66	0.54	0.73
Year current complex opened	1974	1968	1985	1963	1958	1950(4)
Total tons mined since inception (thousands of tons)	191,629	465,456	201,982	109,966	16,725	184,266

 ____________________

(1) Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates. The Jewett Mine’s reserves are covered under two separate mining permits, which must be renewed every five years.

13

(2) Approximate heat content applies to the coal mined in 2014.

(3) Approximate sulfur content applies to the tons mined in 2014.

(4) The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2014.

With the exception of the Jewett and Kemmerer Mines, where we control some reserves through fee ownership, we lease all of our coal properties in our Coal - U.S. Segment. We are a party to coal leases with the federal government, state governments, and private parties at our Absaloka, Rosebud, Beulah, Savage and Jewett Mines. Each of the federal and state government leases continue indefinitely provided there is diligent development of the property and continued operation of the related mines. Federal statute generally sets production royalties on federal leases at 12.5% of the gross proceeds of coal mined and sold for surface mines. At the Beulah and Savage Mines, we have received reductions in the federal royalty rate due to the quality of the lignite coal mined. Our private leases run for an average term of twenty years and have options for renewal. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.

We are a party to two leases with the Crow Tribe covering 18,406 acres of land at our Absaloka Mine, which are held by our wholly owned subsidiary, Westmoreland Resources, Inc. ("WRI"). In 2008, and in order to take advantage of certain Indian Coal Tax Credits (“ICTC”) for the production of coal on the leased Crow Tribe land, WRI entered into a series of transactions, including the formation of Absaloka Coal, LLC with an unaffiliated partner. As part of such transaction, WRI subleased its leases with the Crow Tribe to Absaloka Coal, LLC, granting it the right to mine specified quantities of coal with WRI as contract miner. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from the ICTC. The ICTC expired, but we are currently pursuing future monetization of the ICTC in the event that the U.S. Congress extends the ICTC.

14

Coal - Canada Segment Properties

Mines in our Coal - Canada Segment owned or controlled an estimated 716.9 million tons of total proven or probable coal reserves as of December 31, 2014. We conduct our Canadian coal operations primarily through CVRI and PMRU and their respective subsidiaries. Mines in our Coal - Canada Segment control coal reserves and deposits through a combination of long-term Crown or third-party leases or through fee ownership. The majority of PMRU’s coal production is sold to Canadian utilities for electricity production, and all of PMRU’s five mines are mine mouth operations (where our mine is adjacent to the customer’s property). CVRI produces thermal coal which is exported primarily to the Asian market via rail and reserved port capacity. Our Alberta and Saskatchewan mines are permitted in accordance with the legislation in effect in those Provinces. We secure all of our final reclamation obligations by reclamation bonds as required by the respective provincial agencies. We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.

The following table provides information about mines in our Coal - Canada Segment as of December 31, 2014:

Coal - Canada	Paintearth	Genesee	Sheerness	Poplar River	Coal Valley	Estevan	Total
Owned by	Prairie Mines & Royalty ULC	Prairie Mines & Royalty ULC	Prairie Mines & Royalty ULC	Prairie Mines & Royalty ULC	Coal Valley Resources Inc.	Prairie Mines & Royalty ULC
Location	Forestburg, AB	Warburg, AB	Hanna, AB	Coronach, SK	Edson, AB	Estevan, SK
Coal reserves (thousands of tons) Proven	22,205	259,863	33,603	101,182	3,166	186,922	606,941
Probable	—	41,880	3,452	3,621	12,713	48,330	109,996
Total proven and probable reserves (thousands of tons)	22,205	301,743	37,055	104,803	15,879	235,252	716,937
Permitted reserves (thousands of tons)	22,205	301,743	2,675	77,777	3,166	189,459	597,025
2014 production (thousands of tons)	1,825	3,709	2,480	2,529	1,368	3,818	15,729
Estimated life of permitted reserves(1)	2022	2068	2024	2034	2017	2043
Lessor	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold	Ÿ  Private parties Ÿ  Provincial Government Ÿ  Freehold
Lease term	Varies	Varies	Varies	Varies	Varies	Varies
Current production capacity (thousands of tons)	3,000	5,600	3,700	4,000	4,000	6,400
Coal type	Sub-bituminous	Sub-bituminous	Sub-bituminous	Lignite	Bituminous	Lignite
Major customers	Ÿ  ATCO	Ÿ  Capital Power Corporation	Ÿ  ATCO/TransAlta Generation Partnership	Ÿ  Saskatchewan Power Corporation	Ÿ  Asian and domestic customers	Ÿ  Saskatch-ewan Power Corporation
Delivery method	Truck	Truck	Truck	Rail, Truck	Rail, Truck	Truck
Approx. heat content (BTU/lb.)(2)	7,583	8,035	7,228	5,762	10,800	6,636
Approx. sulfur content (%)(3)	0.43	0.20	0.50	<0.99	0.30	0.40
Year current complex opened	1956	1988	1984	1978	1978	1973
Total tons mined since inception (thousands of tons)	137,565,804	109,590	88,954,657	126,233	—	—

____________________

(1) Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.

(2) Approximate heat content applies to the coal mined in 2014.

(3) Approximate sulfur content applies to the tons mined in 2014.

15

Coal reserves and leases in Canada are generally under the jurisdiction of provincial governments. Coal producers, including Westmoreland, gain access to their coal reserves through provincial Crown coal leases, freehold ownership or third party leases or subleases. Most of CVRI's coal reserves are held through Crown and third-party leases, while PMRU's reserves are held by all three methods, the mix of which varies from mine to mine. Westmoreland's Royalty payments must be paid regardless of the method of ownership.

Alberta Crown coal leases are granted under the Mines and Minerals Act (Alberta) for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to the Mines and Minerals Act (Alberta) and the regulations in force at the time of renewal, and, in the case of any particular renewal, to any terms and conditions prescribed by order of the Minister of Energy. Crown coal royalties are set by the Coal Royalty Regulation (Alberta). Under this regulation, there are two royalty regimes. The royalty rate for Crown-owned sub-bituminous coal is $0.55 per tonne, which is equivalent to $0.50 per ton. The royalty rate for Crown-owned bituminous coal, which is based on a revenue less cost regime, is 1% of mine mouth revenue prior to mine payout, plus an additional 13% of net revenue after mine payout. No provincial royalties or mineral taxes are payable on freehold coal.

Saskatchewan Crown coal leases are granted under The Crown Minerals Act and The Coal Disposition Regulations, 1988, for terms of 15 years. The leases are renewable for further terms of 15 years each, subject to The Crown Minerals Act and the regulations in force at the time of renewal. In Saskatchewan, Crown royalties in the amount of 15% of the mine-mouth value of coal are payable quarterly pursuant to The Crown Coal Royalty Schedule to The Coal Disposition Regulations, 1988. The Mineral Taxation Act, 1983, levies two taxes against freehold coal rights and production. One is an annual freehold mineral tax of $960 per nominal section. The other is a freehold coal production tax, payable quarterly, of 7% on the mine mouth value of coal.

We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in place.

Coal - U.S. and Coal - Canada Segment Customers

U.S. Coal Segment

In 2014, our Coal - U.S. Segment derived approximately 62.7% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (17.6%); Naughton Power Station (14.0%); Limestone Generating Station (13.8%); Colstrip Units 1&2 (10.9%); and Coyote Station (6.4%). We sell the majority of our tons under contracts with remaining supply obligation terms of three years or more. We provide coal delivery via conveyor belt to our mine-mouth customers, and also sell coal and lignite on a Freight On Board, or FOB, basis to our other customers. The purchaser of coal normally bears the cost of transportation and risk of loss from load-out to its final destination.

Rosebud. The Rosebud Mine has two long-term, cost-plus contracts with the adjacent Colstrip Station power generating facility. The supply agreement for Colstrip Units 1 and 2 has a projected term through 2021 and expected tons of 3.0 million annually. A second agreement for Colstrip Units 3 and 4 provides for approximately 7.0 million tons per year and is set to expire at the end of 2019. The agreement related to Units 3 and 4 also has provisions for specific returns on capital investments.

Absaloka. The Absaloka Mine operates primarily in the open market and has several three- to five-year contracts with various parties. The capacity of the mine ranges between 5.5 million and 7.4 million tons annually. In 2012 and 2013, the Absaloka Mine shipped 2.7 million and 4.2 million tons, respectively. The low annual sales in 2012 and 2013 relative to mine capacity were due to an extended outage of the Sherburne County Generating Station in Becker, Minnesota, which is the mine’s largest customer.Burlington Northern Santa Fe (“BNSF”) provides rail service to the mine, which also has the ability to load and ship coal via over-the-road trucks. Prices under these agreements are based upon certain actual mine costs and certain inflation indices for such items as diesel fuel.

Savage. The Savage Mine supplies approximately 0.3 million tons annually to the Lewis & Clark Power Station and Sidney Sugars Incorporated. Both customers are located within close proximity to the mine and coal deliveries are provided via over-the-road truck. The mine entered into new agreements with both customers in 2012 that both expire in December 2017. Prices under these agreements are based on certain actual mine costs, commodity indices (for items such as diesel fuel), and the agreements contain provisions for capital recovery.

Jewett. The Jewett Mine has a cost-plus agreement with NRG Texas Power’s adjacent Limestone Generating Station. NRG Texas Power is also responsible for the mine’s capital and reclamation expenditures. The agreement has a term through 2018, which may be extended by NRG Texas Power for up to an additional ten years or until the mine’s reserves are exhausted. NRG has the option to determine volumes to be delivered, which average between four and five million tons annually. NRG may terminate the agreement at its discretion.

16

Beulah. The Beulah Mine supplies approximately 2.5 million tons annually to the adjacent Coyote Electric Generating Plant via conveyor belt under an agreement that expires in May 2016. The Coyote agreement has provisions for specific returns on capital investment. We have received notice that the Coyote Electric Generating Plant will not be renewing its contract past 2016. The Beulah Mine also supplies approximately 0.5 million tons annually via rail to the Heskett Power Station under an agreement that expires in 2016. Prices under these agreements are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel.

Kemmerer. The Kemmerer Mine supplies approximately 2.7 million tons per year to the adjacent Naughton Power Station via conveyor belt under an agreement that expires in December 2021. Kemmerer also supplies approximately 1.7 million tons a year to various industrial customers through long-term contracts extending to 2026. The Kemmerer Mine services industrial customers via both short haul rail and truck to Trona plants in Green River, Wyoming. Prices under supply agreements related to the Kemmerer Mine are based upon certain actual mine costs and certain inflation/commodity indices for items such as diesel fuel. We recently extended our contracts with both Tata Chemicals North America Inc. and FMC Corporation related to the Kemmerer Mine through 2026. Certain of the Kemmerer mine reserves were contributed to WMLP as part of our acquisition of the GP. See “Coal - WMLP Segment - Customers.”

Coal - Canada Segment Customers

Our Coal - Canada Segment sells the majority of its tons under contracts with remaining supply obligation terms of between one and 40 years. In 2014 our Coal - Canada Segment derived approximately 54.8% of its total revenues from coal sales to two customers: SaskPower (37.2%) and ATCO (17.6%). The majority of PMRU’s coal production is sold to Canadian utilities for electricity production, and all of PMRU’s five mines are mine mouth operations (where our mine is adjacent to the customer’s property). CVRI produces thermal coal which is exported primarily to the Asian market via rail and reserved port capacity.

Paintearth. The Paintearth Mine is a surface mine located in Central Alberta south of the Village of Forestburg. The mine operates two active pits and supplies sub-bituminous coal to the four generating units at the Battle River Generating Station which are owned and operated by ATCO Power. Current annual production of the mine is 3.2 million tons. The coal supply contract for the mine expires in 2022.

Sheerness. The Sheerness Mine is a surface mine located in South Central Alberta south of the Town of Hanna. The mine operates two active pits and supplies sub-bituminous coal to the two generating units at the Sheerness Generating Station which is owned by TransAlta Utilities and ATCO Power and operated by ATCO Power. Current annual production of the mine is 4.0 million tons. The current coal supply contract for the mine expires in 2026.

Poplar River. The Poplar River Mine is a surface mine located in South Central Saskatchewan near the Town of Coronach. The mine operates two active pits and supplies lignite coal to the two generating units at the Poplar River Generating Station which is owned and operated by Saskatchewan Power Corporation ("SaskPower"). Current annual production of the mine is 3.6 million tons. The current coal supply contract for the mine expires on December 31, 2015. The Poplar River Mine owns and operates the railway from the mine to the generating station. Work is underway to execute an extension of the existing coal contract.

Estevan. The Estevan Mine combines two of our adjacent mines in southeastern Saskatchewan, the Bienfait Mine and the Boundary Dam Mine, which supply an approximate combined 6.1 million tons per year to SaskPower, domestic consumers and the char and activated carbon plants. We recently extended our contract with SaskPower related to the Estevan Mine through 2024. The Estevan Mine operates four active pits and supplies lignite coal to the Boundary Dam Generating Station (5 Units) ("Boundary Dam"), the Shand Generating Station (2 Units) ("Shand"), the activated carbon plant, the char plant, as well as some domestic sales. SaskPower has constructed and commissioned a carbon dioxide capture and sequestration (“CCS”) facility at Boundary Dam and a carbon capture test facility at Shand. This combined project is the largest commercial scale CCS facility in the world, and is funded by the government of Saskatchewan with backing from the Canadian government, and, if successful may mitigate the impact of Canadian GHG regulations on Boundary Dam.

Genesee. The Genesee Mine is a surface mine located in Central Alberta north of the Town of Warburg and close to Edmonton. The mine operates two active pits and supplies sub-bituminous coal to the three units at the Genesee Generating Station which are owned by Capital Power and TransAlta Utilities and operated by Capital Power. The Genesee Mine, which is a joint venture between Capital Power and Westmoreland, supplies approximately 5.0 million tons per year to Capital Power and the contract runs for the life of the mine through 2055.

Coal Valley. The Coal Valley Mine is a surface mine located in west central Alberta south of the Town of Edson. The mine operates both truck/shovel and dragline pits and utilizes a dragline for coal removal. The mine exports high quality sub-bituminous coal to customers in Japan and Korea as well as supplying some domestic customers. Current annual production of the mine is 3.3 million tons and the plant has capacity to operate at approximately 4.0 million tons per year.

17

Activated Carbon Plant. A 50/50 joint venture with Cabot Corporation, the plant was initially commissioned in June 2010. On September 30, 2014, we announced an agreement with our joint venture partner to build a second activated carbon plant at the Estevan Mine. The new plant will be co-located with the existing plant and will produce activated carbon products for international sale. We expect to commission the new plant in 2017 and expect its initial capacity to be approximately 35 million pounds of powdered activated carbon.

Char Plant. Our char plant produces approximately 105,000 tons of lignite char per year using coal from the Estevan Mine. The char is sold to BBQ briquette producers.

Competition

While the North American coal industry is intensely competitive, we focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants. For our open market coal sales, we compete with many other suppliers of coal to provide fuel to power plants. Additionally, coal producers compete with producers of alternative fuels used for electrical power generation, such as nuclear energy, natural gas, hydropower, petroleum and wind. Costs and other factors such as safety, environmental and regulatory considerations relating to these alternative fuels affect the overall demand for coal as a fuel.

Coal - U.S. Segment

We believe that our mines have a competitive advantage based on three factors:

• all of the mines in our Coal - U.S. Segment are the most economic suppliers to each of their respective principal customers, as a result of transportation advantages over our competitors in each of our key U.S. markets;

• nearly all of the power plants we supply were specifically designed to use our coal; and

• the plants we supply are among the lowest cost producers of electric power in their respective regions and are among the cleaner producers of power from solid fossil fuels.

Because of the foregoing, we believe that our current customers in our Coal - U.S. Segment are more likely to be dispatched to produce power and to continue purchasing coal extracted from our Coal - U.S. Segment mines.

The principal customers of the Rosebud, Jewett, Beulah and Kemmerer Mines are located adjacent to the mines; we deliver the coal for these customers by conveyor belt instead of more expensive means such as truck or rail. The customers of the Savage Mine are located approximately 20 to 25 miles from the mine so that we can transport coal economically by truck.

The Absaloka Mine faces a different competitive situation. The Absaloka Mine sells its coal in the rail market to utilities located in the northern tier of the United States served by BNSF. These utilities may purchase coal from us or from other producers. We compete with other producers based on price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine enjoys an over 300-mile rail advantage over its principal competitors from the Southern Powder River Basin in supplying customers located in the northern tier. Rail rates have increased over the last several years by 50 to 100%, which strengthens our competitive advantage.

Coal - Canada Segment

The principal customers of the Paintearth, Sheerness, Genesee, Poplar River and Estevan Mines have power plants that are located adjacent to the mines and the coal is delivered to these customers economically by truck.  Our proximity gives us a distinct advantage over our competition.

The Coal Valley Mine produces coal for export customers, and has contracts with railway and port entities for delivery. The coal is first railed to and then sold at, port facilities on the coast of British Columbia, Canada.  The export customers are generally Asian power utilities. Our export customers may purchase coal from us or from other producers around the world with similar coal quality, access to ports, and economical shipping to the customer. Some competitors are located closer to the Asian customers' facilities.

Coal - WMLP Segment

General

WMLP is a low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and is the largest producer of surface mined coal in Ohio. WMLP operates a single business segment and has four operating subsidiaries, Oxford Mining Company, LLC (“Oxford”), Oxford Mining Company-Kentucky, LLC, Westmoreland Kemmerer Fee Coal Holdings, LLC and Harrison Resources. WMLP markets its coal primarily to large electric utilities with coal-fired, base-load scrubbed power plants under coal sales contracts. It focuses on acquiring thermal coal reserves that it can efficiently mine with

18

its large-scale equipment. Its reserves and operations are strategically located to serve its primary market area of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia.

  As of December 31, 2014, WMLP’s management estimated that WMLP owned or controlled approximately 106.5 million tons of coal reserves, of which it has leased or subleased 54.7 million tons of reserves to others. The estimates are based on an initial evaluation, as well as subsequent acquisitions, dispositions, depletion of reserves, changes in available geological or mining data and other factors.

For the year ended December 31, 2014, WMLP sold 5.5 million tons of coal, compared to 6.6 million tons for the year ended December 31, 2013, of which approximately 5.5 million and 6.1 million tons, respectively, were produced from its mining activities, and 0.1 million and 0.5 million tons, respectively, were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average purchase price of $26.33 and $49.00, respectively, for the years ended December 31, 2014 and 2013.

Customers

WMLP’s primary customers are electric utility companies, predominantly operating in its six-state market area, that purchase coal under long-term coal sales contracts. Substantially all of its customers purchase coal for terms of one year or longer, but it also supplies coal on a short-term or spot market basis for some of its customers. For the year ended December 31, 2014, WMLP derived approximately 99.1% of its total coal revenues from sales to its ten largest coal customers, with the following top three coal customers and their affiliates accounting for approximately 87.5% of its coal revenues for that period: American Electric Power Company, Inc. (56.7%); FirstEnergy Corp. (16.5%); and East Kentucky Power Cooperative (14.3%). A portion of these sales were facilitated by coal brokers.

WMLPProperties

As of December 31, 2014, WMLP operated 13 active surface mines and managed these mines as five mining complexes located in eastern Ohio. These mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from one or more of its 13 active mines. The mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. WMLP also owns and operates seven augers, moving them among its mining complexes, as necessary, and two highwall miner systems. Additionally, in 2014 WMLP contracted with a third party to operate two additional highwall miner systems owned by the third party.

Currently, WMLP owns or leases most of the equipment utilized in its mining operations and employs preventive maintenance and rebuild programs to ensure that its equipment is well maintained. The mobile equipment utilized at its mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition.

The following table provides information about the mines held by WMLP as of December 31, 2014. This table does not include any royalty properties as they are discussed below at in the "Royalty Revenues" section. Production and reserve numbers for Kemmerer Mine are disclosed in the Coal- U.S. segment:

19

	Cadiz	Tuscarawas	Plainfield	Belmont	New Lexington	Noble	Muhlenberg(5)	Tusky(4)	Total
Owned by	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company, LLC	Oxford Mining Company - Kentucky, LLC	Oxford Mining Company, LLC
Location	Harrison County, Ohio	Tuscarawas County, Ohio	Muskingum, Guernsey and Coshocton Counties, Ohio	Belmont County, Ohio	Perry, Athens and Morgan Counties, Ohio	Noble and Guernsey Counties, Ohio	Muhlenberg and McLean Counties, Kentucky	Harrison and Tuscarawas Counties, Ohio
Coal reserves (thousands of tons) Proven	7,148	5,966	3,447	10,122	5,596	1,311	15,165	18,965	67,720
Probable	743	—	—	619	521	16	1,131	5,366	8,396
Total proven and probable reserves (thousands of tons)	7,891	5,966	3,447	10,741	6,117	1,327	16,296	24,331	76,116
Permitted reserves (thousands of tons)	6,097	3,101	265	2,875	1,717	26	8,383	16,720	39,184
2014 production (thousands of tons)	3,074	1,185	—	403	685	251	—	—	5,598
Estimated life of permitted reserves(1)	2018	2018	2017	2016	2017	2015	2020+	2025+
Lessor	Private parties	Private parties	Private parties	Private parties	AEP, Private parties	Private parties	Private parties	Private parties
Lease term	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion	Through exhaustion
Current production capacity (thousands of tons)	2,604	1,176	—	840	900	240	—	—
Coal type	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous	Bituminous
Major customers	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	American Electric Power Company, Inc. ; FirstEnergy Corp.; and East Kentucky Power Cooperative	N/A - See Note 2	N/A - See Note 1
Delivery method	Barge, Rail, Truck	Truck	Truck	Barge	Rail	Barge, Truck
Approx. heat content (BTU/lb.)(2)	11,350	11,775	11,703	11,804	11,177	11,239	11,314	12,900
Approx. sulfur content (%)(3)	2.70	4.10	4.40	4.30	4.10	4.80	3.60	2.10
Year current complex opened	2000	2003	1990	1999	1993	2006	2009	2003

 ____________________

(1) Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.

(2) Approximate heat content applies to the coal mined in 2014.

(3) Approximate sulfur content applies to the tons mined in 2014.

(4) WMLP began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, WMLP sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are 8 years remaining on WMLP's lease for the underground coal reserves, and

20

the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have WMLP assign its interest to the sublessee for defined and predetermined consideration. For the year ended December 31, 2014, WMLP did not recognized any royalty revenue on the sublease of the Tusky reserves.

(5) This mining complex was idled in December 2013 and remained idled throughout year ended December 31, 2014. WMLP is seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Royalty Revenues

Kemmerer Coal Reserves

We have entered into a coal mining lease with Westmoreland Kemmerer Fee Coal Holdings, LLC ("WKFCH"), a wholly owned subsidiary of WMLP, with respect to 30.4 million tons of coal reserves and related surface lands at Westmoreland’s Kemmerer Mine in Lincoln County, Wyoming, pursuant to which WMLP will earn a per ton royalty as these coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves is expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025.

Tusky Coal Reserves

WMLP began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, WMLP sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are eight years remaining on WMLP's lease for the underground coal reserves, and the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have WMLP assign its interest to the sublessee for defined and predetermined consideration. For the year ended December 31, 2014, WMLP did not recognize any royalty revenue on the sublease of the Tusky reserves.

Oil and Gas Reserves

In December 2014, June 2013 and April 2012, WMLP completed the sale of certain oil and gas rights on land in eastern Ohio for $0.2 million, $6.1 million and $6.3 million, respectively, plus future royalties. For the fiscal year ended December 31, 2014, WMLP generated $0.3 million in royalty revenue from the receipt of these oil and gas royalties.

Limestone Revenues

     At WMLP’s Daron, Pickens, and Strasburg mines, limestone is removed in order to access the underlying coal. WMLP sells this limestone to a third party that crushes the limestone before selling it to local governmental authorities, construction companies and individuals. The third party pays WMLP for this limestone based on a percentage of the revenue it receives from the limestone sales. For the year ended December 31, 2014, WMLP produced and sold 1.6 million tons of limestone, and its revenues included $4.7 million in limestone sales. Limestone at the Pickens mine was fully depleted in 2014.

Competition

The markets in which WMLP sells its coal are highly competitive. It competes directly with other coal producers and indirectly with producers of other energy products that provide an alternative to coal. While WMLP does not compete with producers of metallurgical coal or lignite, it does have limited competition from producers of Power River Basin coal (sub-bituminous coal) in its target market area for bituminous coal. WMLP competes on the basis of delivered price, coal quality and reliability of supply. Its principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, Arch Coal, Inc., CONSOL, Foresight Energy, Hallador Energy Company, James River Coal Company, Murray Energy Corp., Patriot Coal Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.

Debt Facility

WMLP has a $295 million credit facility (the “WMLP Loan”) which is governed by a Financing Agreement (the “WMLP Financing Agreement”) among Oxford, WMLP and certain of its subsidiaries as guarantors, the lenders party thereto and U.S. Bank National Association as administrative and collateral agent. The WMLP Loan consists of an initial $175 million term loan and delayed draw term loans in the aggregate principal amount of up to $120 million, which may be requested by Oxford to finance a portion of certain permitted acquisitions. The WMLP Financing Agreement provides that the WMLP Loan matures in December 2018 and contains customary financial and other covenants. It also permits distributions to

21

WMLP’s unitholders under specified circumstances. Borrowings under the WMLP Financing Agreement are secured by substantially all of WMLP’s and its subsidiaries’ assets.

Seasonality

Our coal business has historically experienced only limited variability in its results due to the effect of seasons; however, we are impacted by seasonality due to weather patterns and our customer's annual maintenance outages which typically occur during the second quarter. In addition, our customers generally respond to seasonal variations in electricity demand based upon the number of heating degree days and cooling degree days. Due to stockpile management by our customers, our coal sales may not experience the same direct seasonal volatility; however, extended mild weather patterns can impact the demand for our coal. Our sales typically benefit from decreases in customers' stockpiles due to high electricity demand. Conversely, when these stockpiles increase, demand for our coal will typically soften. Further, our ability to deliver coal is impacted by the seasons. Because the majority of our mines are mine-mouth operations that deliver their coal production to adjacent power plants, our exposure to transportation delays or outages as a result of adverse weather conditions is limited.

Material Effects of Regulation

We are subject to extensive regulation with respect to environmental and other matters by federal, state, provincial and local authorities in both the United States and Canada. Federal laws in the U.S. to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration ("MSHA"). Provincial laws in Alberta to which we are subject include, among others, the Responsible Energy Development Act, the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act as well as related regulations, directives, policies and guidelines. Provincial laws in Saskatchewan to which we are subject include, among others, The Crown Minerals Act, The Ecological Reserves Act, The Environmental Assessment Act, The Environmental Management and Protection Act, 2002, The Provincial Lands Act, and the Wildlife Act, 1998, as well as related regulations, directives, policies and guidelines. The federal laws in Canada to which we are subject include, among others, the Fisheries Act, the Canadian Environmental Assessment Act, 2012, the Canadian Environmental Protection Act, 1999, the Species at Risk Act, the Migratory Birds Convention Act as well as related regulations, directives, policies and guidelines, and various provincial and federal climate change laws and initiatives. Non-compliance with federal, tribal and state and provincial laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial. Certain of our coal sales agreements contain government imposition provisions that allow the pass-through of compliance costs in some circumstances.

Safety is a core value of Westmoreland Coal Company. We use a grass roots approach, encouraging and promoting employee involvement in safety and accept input from all employees; we feel employee involvement is a pillar of our safety excellence. In 2012, our Rosebud Mine received the Sentinels of Safety award in the large surface coal category.

During 2014, we continued to maintain reportable and lost time incident rates significantly below national averages as indicated in the table below.

	2014
	Reportable Rate	Lost Time Rate
U.S. Operations (excluding WMLP mines)	1.29	0.88
U.S. National Average	1.71	1.19
	Recordable	Lost Time
Canadian Operations (April 28, 2014 through December 31, 2014)	4.82	0.71

22

During 2014, WMLP continued to maintain reportable and lost time incident rates significantly below Appalachian averages as indicated in the table below.

	2014
	Reportable Rate	Lost Time Rate
WMLP mines	1.14	0.50
Appalachian mines average	2.15	1.56

Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal, state and provincial safety and health regulations in the coal mining industry are comprehensive and pervasive systems for protection of employee health and safety.

U.S. Regulation

The following provides brief summaries of certain U.S. federal laws and regulations to which we are subject and their effects upon us:

Surface Mining Control and Reclamation Act. SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement ("OSM"), or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affects the cost and availability of coal purchased by ROVA, especially in light of significant permitting issues affecting the Central Appalachia region. This difficulty in permitting also affects the availability of coal reserves at our coal mines.

It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation. In 2012, our Jewett Mine received the 2012 Railroad Commission of Texas Core Mining Reclamation Award for its innovative techniques in stream channel restoration.

Clean Air Act and Related Regulations. The U.S. federal Clean Air Act ("CAA"), and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include Clean Air Act permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired power plants. It also affects us directly because ROVA is subject to significant regulation under the Clean Air Act. In recent years, Congress has considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:

Greenhouse Gas Emissions Standards. In April 2012, the EPA proposed new limits on GHG emissions from new electric generating units (“EGUs”) under Section 111 of the CAA (“GHG NSPS”). The proposed limits are referred to as “new source performance standards” because they apply only to new or reconstructed sources. The proposal required all new fossil-fuel-fired EGUs to emit no more than 1,000 pounds of CO2 / megawatt hour on an average annual basis, which is based on the CO2 emissions from natural gas combined cycle facilities. The EPA later indicated its intention to issue a new proposal in light of over two million comments on the April 2012 proposal and ongoing developments in the industry. In June 2013, President Obama directed the EPA to issue that new proposal by September 30, 2013, and to finalize it in a timely manner. In September 2013, the EPA revoked its April 2012 proposal and instead proposed new limits, which would require all new coal-fired EGUs to emit no more than 1,100 pounds of CO2 / megawatt hour on an average annual basis, and new natural gas-fired plants to meet a standard of either 1,000 or 1,100 pounds of CO2 / megawatt hour (depending on size). Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal. Once NSPSs are finalized, the EPA must issue guidance to states for the issuance of existing source standards. The GHG NSPS as currently proposed may be a major obstacle to the construction and development of any new coal-fired

23

generation capacity because it is unlikely, with a few possible exceptions, that the limits in the proposal can be achieved by a new coal-fired EGU without the use of carbon capture and sequestration technology. EPA has stated that it will finalize the NSPS in the summer of 2015. The finalization of the NSPS is a predicate for issuance of existing source performance standards under Section 111(d) of the CAA. In June of 2014, EPA proposed existing source standards for fossil-fuel fired power plants, which EPA refers to as the Clean Power Plan. EPA’s proposal mandates GHG emission “goals” for each state, beginning in 2020 with reductions through 2030, based on EPA’s assessment of the “best system of emission reduction,” including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to 70%; (3) the substitution of coal generation with renewable energy; and (4) cumulative annual energy savings rates of 1.5% based on demand-side energy efficiency programs. EPA plans to finalize the rule in the summer of 2015. Once finalized, the states have one year to submit plans to EPA to implement and enforce the state-specific BSER. EPA has stated that if finalized, the Plan would reduce GHG emissions from the power sector by 30 percent from 2005 levels, due primarily to reduced generation at coal-fired power plants.

• Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs. The “Mercury Air Toxics Standards,” or “MATS Rule,” is expected to be one of the most costly rules ever issued by the EPA. It has also proven highly controversial, drawing numerous legal challenges in the U.S. Court of Appeals for the D.C. Circuit as well as petitions for administrative reconsideration filed with the EPA. While the MATS Rule will generally require all coal- and oil-fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. This is because the new-source limits are so low that they cannot be accurately measured and vendors of pollution control equipment have said they cannot provide commercial guarantees that the limits can be achieved. And because such guarantees are a precondition to obtaining financing in the marketplace, the MATS Rule effectively amounts to a ban on the construction of new coal-fired EGUs. In July 2012, however, the EPA agreed to reconsider the new source standards in response to requests by industry. In November 2012, the EPA published proposed new source standards with revised, less stringent, emission limits. In April 2013, the EPA published new source limits under the MATS Rule, and then in June 2013, the EPA reopened for 60 days the public comment period on certain startup and shutdown provisions included in the November 2012 proposal. In June 2013, certain environmental organizations and industry groups filed appeals of the rule as revised. The D.C. Circuit upheld the standards, but the Supreme Court accepted certiorari and will hear an industry challenge in 2015.

• National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. EPA finalized designations for the sulfur dioxide NAAQS in 2013 for a handful of counties and delayed designations for the remainder of the country. EPA has proposed guidance that would allow states to use both monitoring and modeling for the remaining designations, but has not finalized the guidance or set any deadlines for state recommendations. EPA finalized nonattainment designations for nitrogen dioxide in January 2012. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses. In 2008, the EPA finalized the current 8-hour ozone standard. The EPA agreed to reconsider the standard, and in 2010 the EPA proposed to further reduce the standard. Under orders from President Obama, this NAAQS was not finalized. In December 2014, EPA proposed to lower the primary ozone standard to between 65 ppb and 70 ppb from the current standard of 75 ppb, which would result in disproportionate impacts on the western U.S. EPA is obligated by court order to finalize the standards by October of 2015.

• Clean Air Interstate Rule and Cross-State Air Pollution Rule. (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels ofsulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain.In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, butultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because ofconcerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule

24

to the CAIR,which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions thatcross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phaseof the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In January 2013, the court rejected the EPA’s request for en banc review. In March 2013, the Solicitor General’s office, on behalf of the EPA, and separately certain non-governmental organizations, filed petitions for writs of certiorari with the U.S. Supreme Court seeking review of the U.S. Court of Appeals decision, and the U.S. Supreme Court granted those petitions in June 2013. TheSupreme Court reversed the D.C. Circuit and upheld the rule, but remanded the case to the D.C. Circuit for further proceedings, which are ongoing. EPA issued an interim final rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017.

• Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulphur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Indeed, in 2014 the D.C. Circuit upheld EPA’s decision not to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from coal mines.

• Effect on Westmoreland Coal Company. Our mines do not produce “compliance coal” for purposes of the Clean Air Act. Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit, or Btu. This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act. Our coal also contains about fifty percent more ash content than our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled. We are at particular risk of changes in applicable environmental laws with respect to the Jewett Mine, whose customer, the NRG Texas Power- Limestone Station, blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in an increased blend of the Wyoming coal to reduce emissions. Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, NRG Texas Power has the option to increase its purchases of other coal, reduce purchases of our coal, or to terminate our contract. If NRG terminates the contact, sales of lignite would end and the Jewett Mine would commence final reclamation activities. NRG would pay for all reclamation work plus a margin.

Clean Water Act. The Clean Water Act ("CWA") and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly released a proposed rule to clarify which waters and wetlands are subject to regulation under the CWA. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.

Endangered Species Act. The Federal Endangered Species Act ("ESA"), and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that

25

have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.

Resource Conservation and Recovery Act. We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. The rule is largely silent on the reuse of coal ash, but the EPA has plans to develop in 2015 a conceptual model for beneficial uses of coal ash. These changes in the management of CCR could increase both our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation, and Liability Act. Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

Climate Change Legislation and Regulations. Numerous proposals for federal and state legislation have been made relating to GHG emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Some states, including California, and a number of states in the northeastern and mid-Atlantic regions of the US that are participants in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”), which is limited to fossil-fuel-burning power plants, have enacted and are currently operating programs that, in varying ways and degrees, regulate GHGs.

In addition, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to EPA’s GHG Reporting

26

Program, which required mines to submit annual GHG emission estimates to EPA, but that program has not been extended to surface coal mines.

The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover from our customers the costs related to compliance with regulatory requirements imposed on us due to limitations in our agreements.

Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.

Bonding Requirements. Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more favorable to us. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of December 31, 2014, we had posted an aggregate of $461.4 million in surety bonds for reclamation purposes, with approximately $102.2 million of cash collateral.

Regulation applicable to ROVA. With respect to our Power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. All preliminary emission testing performed in 2014 has demonstrated that both ROVA units 1 and 3 will be compliant with the MATS Rule. Official testing for compliance with the MATS Rule will be performed in segments, beginning in January 2015. The final emissions testing report for MATS Rule compliance is due to the EPA by October 13, 2015. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide credits, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. The landfills are lined and we believe they meet North Carolina Department of Solid Waste regulations. However, on December 19, 2014, the EPA Administrator executed a final rule relating to the disposal of CCR for electric utilities. The rule regulates CCR as a solid waste under RCRA and establishes national minimum criteria for existing and new CCR landfills, surface impoundments and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and internet posting requirements. At this time we are unable to predict the impact that any new regulations might have on our operations.

An important factor relating to the impact of GHG-related legislation and regulations and any other environmental regulations on our Power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not be able to recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to recover such costs incurred by ROVA through allowances or other methods, it could have a material adverse effect on our results of operations at ROVA.

27

Canadian Regulation

The following is intended as a general overview of certain provincial laws and regulations in Alberta and the federal laws applicable therein to which we are subject and their potential effects upon us. We note that the consequences and penalties arising from the application of any of the below listed enactments are varied and fact specific. Accordingly, the summary that follows should not be considered a comprehensive or conclusive assessment of the possible outcomes of a contravention of the legislation discussed below:

Responsible Energy Development Act. The Responsible Energy Development Act (the “REDA”) establishes the Alberta Energy Regulator (the “AER” or the “Regulator”) and sets out its mandate, structure, powers, duties and functions. The AER administers, among others, the following statutes and accompanying regulations in relation to coal mining and related activities in Alberta: the Mines and Minerals Act, the Coal Conservation Act, the Environmental Protection and Enhancement Act, the Public Lands Act, and the Water Act. The REDA empowers the AER to carry out compliance and enforcement functions under the various pieces of legislation it administers as well as grants it the power to order the payment of administrative penalties.

Mines and Minerals Act. The Mines and Minerals Act (the “MM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The AER recently assumed jurisdiction over issuing exploration authorizations under the MM Act, which any person conducting mining exploration in Alberta is required to obtain in advance of carrying out an exploration program. Exploration programs under the MM Act are subject to investigations and inspections and a contravention of an exploration authorization or of the provisions of the MM Act may result in cancellation of that exploration authorization and/or financial penalties.

Coal Conservation Act. The Coal Conservation Act (the “CC Act”), and its underlying rules, applies to every mine, coal processing plant and in situ coal scheme in the Province of Alberta, and to all coal produced and transported in Alberta. The CC Act imposes permitting, licensing and approval requirements on operators of coal mines and coal processing plants. The CC Act imposes certain environmental conservation requirements on mine operators in relation to, among other things, pollution control, surface abandonment, and prevention of waste. Similar to the US bonding requirements mentioned above, the Regulator may require that we deposit financial security to ensure payment of costs associated with suspension of our operations and/or reclamation. Lastly, under the CC Act the Regulator can conduct an inquiry into any matter connected with our Alberta mining operations, the findings of which may result in prosecution for an offense, financial penalties, or injunctions in relation to our operations.

Environmental Protection and Enhancement Act. Under the Environmental Protection and Enhancement Act (the “EPEA”), and its underlying regulations, the AER is responsible for administering environmental impact assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Alberta that have the potential to impact the environment. The specific terms and conditions of an EPEA approval may govern emission and effluent limits, monitoring and reporting requirements, research needs, siting and operating criteria, and decommissioning and reclamation requirements. The AER also administers and enforces provisions under the EPEA that concern spills and releases, contaminated sites, land surface reclamation, and hazardous wastes. The Mine Financial Security Program under the EPEA requires us to have sufficient financial resources for carrying out suspension, abandonment, remediation, and surface reclamation work to the standards established by the province and to maintain care and custody of the land until a reclamation certificate has been issued. The Regulator may exercise broad enforcement powers under the EPEA, including conducting compliance checks, inspections and investigations, issuing enforcement orders, taking enforcement actions, issuing clean-up orders, suspending and/or canceling operating authorizations, demanding cost recovery or charging us for an offense under the EPEA; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Regulator.

Public Lands Act. Under the Public Lands Act, the AER carries out its responsibility of ensuring that energy exploration, development, and ongoing operations on public land, including coal mining, are carried out in a responsible manner and in accordance with applicable legislation. The AER amends, maintains, and inspects all land-use dispositions and authorizations for energy activities. The AER also administers the enforcement and compliance provisions of the Public Lands Act, which empower it to cancel, suspend or amend a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offences under the Public Lands Act. Similar to contraventions of other pieces of legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.

Water Act. The Water Act, and its underlying regulations, requires that authorizations be obtained prior to undertaking construction activities around, and prior to diverting water from, a water body. Under the Water Act, a corporation conducting an activity without the requisite approval or in contravention of the specific terms and conditions of an authorization is liable to a fine and/or administrative penalty, which may have a material adverse effect on our business.

28

The Crown Minerals Act. Similar to the MM Act in Alberta, the Crown Minerals Act (the “CM Act”), and its underlying regulations, governs the management and disposition of rights in Crown owned mines and minerals. The Saskatchewan Ministry of Economy administers the CM Act and the issuance of dispositions authorizing the exploration and development of coal resources in the province. Contravention of the terms of a Crown disposition or the provisions of the CM Act may result in cancellation of that disposition and/or financial penalties, both of which may have a material adverse effect on our business.

The Ecological Reserves Act. The Ecological Reserves Act (the “ER Act”) protects unique, natural ecosystems and landscape features in Saskatchewan through the designation of Crown land as ecological reserves. Under the ER Act, the Lieutenant Governor in Council may make regulations and orders designating any Crown land as an ecological reserve, enlarging any ecological reserve, and restricting the activities which may be carried out on an existing ecological reserve. Designation of either of our Saskatchewan mine properties as an ecological reserve may restrict our mining activities on those properties, or cause us to modify mining plans; however, we do not have any reason to believe that either of our Saskatchewan properties are at risk of being designated an ecological reserve at this time.

The Environmental Assessment Act. The Environmental Assessment Act (the “EA Act”) provides a means to ensure that development proceeds with adequate environmental safeguards and in a manner broadly understood by and acceptable to the public through the integrated assessment of environmental impact. Under the EA Act, the Saskatchewan Ministry of Environment is responsible for administering environmental assessments, and issuing approvals and other authorizations in respect of certain aspects of coal mining operations in Saskatchewan that have the potential to impact the environment. Similar to the AER’s powers in relation to environmental impact assessments issued under the EPEA, the Ministry of Environment may issue an EA Act approval on any terms and conditions considered necessary or advisable to protect the environment. The Ministry of Environment has broad enforcement powers under the EA Act, including enjoining a development contrary to the EA Act or the terms and conditions of any ministerial approval, conducting investigations, and issuing financial penalties for offenses under the EA Act; all of which may have a material adverse effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.

The Environmental Management and Protection Act, 2002. The Environmental Management and Protection Act, 2002 (the “EMP Act”), and its underlying regulations, protects the air, land and water resources of Saskatchewan through regulating and controlling potentially harmful activities and substances. The Saskatchewan Ministry of Environment administers and enforces provisions under the EMP Act that concern unauthorized discharges of substances into the environment, contaminated sites, surface land reclamation, hazardous waste, water quality, and activities around water bodies. The Saskatchewan Ministry of Environment may exercise broad enforcement powers under the EMP Act, including conducting compliance checks, inspections and investigations, issuing environmental protection orders, suspending or canceling operating authorizations, demanding cost recovery or charging us for an offence under the EMP Act; all of which may have a material effect on our business, depending on the specific circumstances surrounding the enforcement action taken by the Ministry of Environment.

The Provincial Lands Act. The Provincial Lands Act (the “PL Act”) creates authority for the Saskatchewan Ministry of Environment to carry out its responsibilities in relation to the management, transfer, sale, lease or other disposition of Crown lands, including lands used for coal mining. The Ministry of Environment also administers the enforcement and compliance provisions of the PL Act, which may include cancellation of a disposition where its terms and conditions or the provisions of the legislation have been contravened and to issue financial penalties in respect of offenses under the PL Act. Similar to contraventions of other legislation discussed in this section, an enforcement action or a penalty has the potential to constitute a material adverse effect on our operations.

The Wildlife Act, 1998. The Wildlife Act, 1998 (the “Wildlife Act”) provides for the management, conservation and protection of wildlife resources through the issuance and revocation of licenses, the prosecution of wildlife offenses and the establishment of annual hunting seasons. The Wildlife Act includes provisions to designate and protect species at risk in Saskatchewan, of which there are currently 15 at-risk plants and animals identified in the Wildlife Act. Identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected under the Wildlife Act; however, we do not believe that there are any species protected under the Wildlife Act that would materially and adversely affect our ability to mine coal from our Saskatchewan properties.

Fisheries Act. The Fisheries Act, and its underlying regulations, contains two key provisions on conservation and protection of fish habitat that have the potential to have a material effect on our business. The Department of Fisheries and Oceans (“DFO”) administers the key habitat protection provision prohibiting any work or undertaking that would cause harm to fish or fish habitat. The Fisheries Act also prohibits the release of deleterious substances into waters frequented by fish. In terms of potential material adverse effects to our business resulting from a contravention of the Fisheries Act, enforcement of the habitat protection and pollution prevention provisions of the Fisheries Act is carried out through inspections to monitor or

29

verify compliance, investigations of violations, issuance of warning, directions by Fishery Inspectors, authorizations and Ministerial orders, and court actions, such as injunctions, prosecution, court orders upon conviction and civil suits for recovery of costs.

Canadian Environmental Assessment Act, 2012. The Canadian Environmental Assessment Act, 2012 (the “CEAA”) is the primary federal statute for environmental assessments. The CEAA requires that an environmental assessment for projects that are listed in the Regulations Designating Physical Activities be completed prior to federal authorities making decisions that allow a project to proceed (i.e. prior to issuing certain licenses, disposing of federal lands, providing funding for a project). Projects that require an environmental assessment under the CEAA include, among others, the construction, operation, decommissioning and abandonment, in a wildlife area or a migratory bird sanctuary, of a new mine; the construction, operation, decommissioning and abandonment of a new dam or dyke or the expansion of an existing dam or dyke in certain circumstances; the construction, operation, decommissioning and abandonment of a new structure for the diversion of certain amounts of water; and the construction, operation, decommissioning and abandonment of a new coal mine with a coal production capacity of 3,000 t/day or more.

Canadian Environmental Protection Act, 1999. The Canadian Environmental Protection Act, 1999 (the “CEPA”) focuses on the prevention and management of risks posed by toxic and other harmful substances, as well as management of environmental and human health impacts of hazardous wastes, environmental emergencies and other sources of pollution. Certain substances used and/or produced, as well as downstream wastes generated through the course of our mining and processing operations may bring our business under the purview of the CEPA. The CEPA provides the authority to carry out inspections and investigations to ensure that regulations made under the CEPA and the CEPA itself are followed. Similar to the enforcement provisions of other environmental laws and regulations discussed herein, enforcement tools under the CEPA may include warnings, directions to prevent releases, tickets, orders requiring remedial measures, injunctions, prosecution, and financial penalties. Subject to the specific circumstances of a contravention of the CEPA, an enforcement action taken under the CEPA has the potential to cause a material adverse effect to our business.

Species at Risk Act. The purposes of the Species at Risk Act (the “SARA”) are to prevent wildlife species in Canada from disappearing, to provide for the recovery of wildlife species that no longer exist in the wild in Canada, endangered, or threatened as a result of human activity, and to manage species of special concern to prevent them from becoming endangered or threatened. The SARA may affect our operations if a species at risk is found at any time throughout the year on a property in Canada in which we have an interest. As with the protection of endangered species legislation in the US, identification of a species at risk may cause us to modify mining plans or develop and implement protection plans to avoid or minimize impacts to species protected by the SARA; however, we do not believe that there are any species protected under the SARA that would materially and adversely affect our ability to mine coal from our properties.

Migratory Birds Convention Act, 1994. Environment Canada is responsible for implementing the Migratory Birds Convention Act, 1994 (the “MBC Act”), which provides for the protection and conservation of migratory bird populations by regulating potentially harmful human activities. The MBC Act prohibits, among other things, the deposit of harmful substances in waters or areas frequented by migratory birds and a permit must be issued for all activities affecting migratory birds. Any person that commits an offence under the MBC Act is liable to a fine or to imprisonment. A contravention of the MBC Act may result in cancellation or suspension of a permit issued under the MBC Act and a compensatory order for costs incurred by others as a result of a contravention may be issued.

Climate Change Legislation and Regulations. Similar to climate change legislation, regulations, and proposals in the US, the direct and indirect costs of various GHG regulations, existing and proposed in Canada, may adversely affect our business. Equipment that meets future emission standards may not be available on an economic basis and other compliance methods to reduce our emissions or emissions intensity to future required levels may significantly increase operating costs or reduce output. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations may materially adversely affect our business and result in fines, penalties and the suspension of operations. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by us or by consumers of our products. The imposition of such measures might negatively affect our costs and prices for our products and have an adverse effect on earnings and results of operations.

Alberta’s Climate Change and Emissions Management Act (the “CCEM Act”) and its accompanying Specified Gas Emitters Regulation (the “SGE Regulation”) requires a reduction in GHG emissions intensity for certain large GHG emitting facilities in Alberta. This system features emissions trading between regulated facilities and allows the use of offsets generated by projects in Alberta. Generally, the SGE Regulation establishes that companies emitting more than 100,000 tons of direct emissions in 2003, 2004, 2005, and 2006 in commercial operation must reduce their net emissions intensity by 12%. New facilities must reduce their emissions by 2% per year, beginning on their 4^th year of operation. There are financial penalties for

30

non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the SGE Regulation.

Future federal legislation, including the implementation of potential international requirements enacted under Canadian law, as well as provincial emissions reduction requirements, may require the reduction of GHG or other industrial air emissions, or emission intensity, from our operations and facilities. Mandatory emissions reduction requirements may result in increased operating costs and capital expenditures. We are unable to predict the impact of emissions reduction legislation on our business and it is possible that such legislation may have a material effect on our business, financial condition, results of operations and cash flows.

Power Segment

General

We own two coal-fired power-generating units in Weldon, North Carolina with a total capacity of approximately 230 megawatts, which we refer to collectively as ROVA. We built ROVA, which commenced operations in 1994, as a Public Utility Regulatory Policies Act co-generation facility to supply Dominion North Carolina Power (“DNCP”). ROVA is held by our wholly-owned subsidiary Westmoreland Partners. All of the tangible and intangible assets of Westmoreland Partners are encumbered by liens securing our 8.75% Notes and Term Loan.

Coal Supply

ROVA purchases coal under short-term contracts from coal suppliers with identified reserves located in Central Appalachia.

Customer

ROVA supplies a portion of the power it produces to DNCP and generates revenues from such sales, as well as through the settlement of related power hedging arrangements. In 2014, the sale of power by ROVA to DNCP accounted for approximately 8% of our consolidated revenues. We are impacted by seasonality due to the impact of weather on customer demand and scheduled maintenance outages typically performed in the spring and fall.

Westmoreland Partners is party to a consolidated power purchase and operating agreement (the “Consolidated Agreement”) with Virginia Electric Power Company that is scheduled to terminate in March 2019. The Consolidated Agreement provides for the sale to DNCP and its affiliates of all of ROVA’s net electrical output and dependable capacity. The Consolidated Agreement permits Westmoreland Partners to mitigate its cash losses through the sale to DNCP of substitute power not produced by ROVA during periods when it is uneconomical to operate the ROVA units. While we expect to continue to operate ROVA during high demand periods, we expect the facility to remain idle during low demand periods, during which we may meet DNCP’s power needs by purchasing power from a third party provider at a fixed price under the terms of related hedging agreements. We refer to the power which we have purchased from a third party provider as the fixed-price purchased power. The fixed-price purchased power contracts cover the period from April 2014 to March 2019 and contracted power prices range from $41.05 to $56.33 megawatts per hour, with a weighted average contract price of $43.71 over the remaining contract lives. Alternatively, we have the option to operate the ROVA units, sell our produced power to DNCP and resell the fixed-price purchased power into the open market.

If we choose to operate the ROVA facilities and resell our fixed price purchased power into the open market, any such resales are made at prevailing market rates. If the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed price purchased power in the open market, those resales would result in losses to us. For the year ended December 31, 2014, we incurred net losses related to these hedging arrangements of $31.1 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position. See “Risk Factors - Risks Relating to our Business and Operations - Our hedging arrangement in connection with the ROVA Consolidated Agreement may result in losses if the market price for power drops below the level of our hedged position.”

We incurred restructuring charges related to ROVA of $5.1 million and $0.5 million for the years ended December 31, 2013 and December 31, 2014, respectively, primarily related to consulting and legal fees.

Material Effects of Regulation Applicable to ROVA

With respect to our power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States. Under Title IV of the Clean Air Act, ROVA is exempt from, but may opt-in to receive allocations of sulfur dioxide emission allowances. The plants are among the lowest coal-fired emitters of mercury in the country. We are evaluating whether

31

ROVA could be a net consumer or seller of mercury allowances under new and pending regulations. Currently, ROVA is a consumer of sulfur dioxide allowances and nitrogen oxide credits, and we expect an increase in costs associated with nitrogen oxide allowances at ROVA. With regard to coal ash regulations, ROVA landfills its combustion waste. Landfills are lined and meet strict North Carolina Department of Solid Waste regulations.

An important factor relating to the impact of GHG-related legislation and regulations on our power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that the government ultimately imposes. We may not recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to pass through such costs incurred by ROVA to Dominion Virginia Power or recoup them in another manner such as through allowances, it could have a material adverse effect on our results of operations at ROVA.

For additional discussion of the extensive regulation with respect to environmental and other matters by federal, state and local authorities affecting our power segment, see Item 1 under “Coal Segment - Material Effects of Regulation.”

Heritage Segment

Our Heritage Segment includes the cost of heritage benefits we provide to former mining operation employees. The heritage costs consist of payments to our retired workers for medical benefits, workers’ compensation benefits, black lung benefits and combined benefit fund premiums to plans for United Mine Workers of America (“UMWA”) retirees required by statute. Canadian heritage costs include retiree medical benefits, statutory workers’ compensation premiums, and contributions to pension plans.

Corporate Segment

Our Corporate Segment includes primarily corporate administrative expenses and also includes business development expenses. In addition, the Corporate Segment contains our captive insurance company, Westmoreland Risk Management Inc. (“WRM”), through which we have elected to retain some of our operating risks. WRM provides our primary layer of property and casualty insurance in the United States. By using this insurance subsidiary, we have reduced the cost of our property and casualty insurance premiums and retained some economic benefits due to our excellent loss record. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third-party insurance companies.

Available Information

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may access and read our filings without charge through the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information regarding the operation of its public reference room.

We also make our public reports available, free of charge, through our website, www.westmoreland.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (303) 992-6463 or by mail at Westmoreland Coal Company, 9540 South Maroon Circle, Suite 200, Englewood, Colorado, 80112. The information on our website is not part of this Annual Report on Form 10-K.

32

ITEM 1A — RISK FACTORS.

This report, including Management’s Discussion and Analysis of Financial Condition and Results of Operation, contains forward-looking statements that may be materially affected by numerous risk factors, including those summarized below.

Risks Relating to our Business and Operations

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

We have a substantial amount of indebtedness. At December 31, 2014, we had a total outstanding indebtedness of approximately $998.0 million, including (i) $350 million in principal amount of 8.75% Notes, (ii) $350 million in principal amount under the Term Loan and (iii) $33.1 million of borrowings and supported letters of credit under our Revolving Credit Facility, respectively, leaving $16.9 million of undrawn availability thereunder. Our substantial amount of indebtedness could have important consequences for you. For example, it could:

• increase our vulnerability to adverse economic, industry or competitive developments;

• result in an event of default if we fail to satisfy our obligations with respect to the 8.75% Notes, the Term Loan, the Revolving Credit Facility or other debt or fail to comply with the financial and other restrictive covenants contained in the Indenture, the Term Loan Credit Agreement, the Revolving Credit Facility Agreement or agreements governing our other indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on our assets securing such debt or otherwise recover that debt from us;

• require a substantial portion of cash flow from operations to be dedicated to the payment of principal, premium, if any, and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

• make it more difficult for us to satisfy our obligations with respect to the 8.75% Notes, the Term Loan and the Revolving Credit Facility;

• increase our cost of borrowing;

• restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;

• limit our ability to service our indebtedness, including the 8.75% Notes, the Term Loan and the Revolving Credit Facility;

• limit our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;

• limit our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting; and

• prevent us from raising the funds necessary to repurchase all 8.75% Notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the Indenture.

The occurrence of any one of these events could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to satisfy our obligations under the 8.75% Notes, the Term Loan and the Revolving Credit Facility.

In conjunction with our acquisition of the GP, WMLP entered into the WMLP Financing Agreement to refinance WMLP’s indebtedness. The WMLP Financing Agreement provides for up to $295 million of first priority secured term loans, with $175 million currently funded and maturing in December 2018, and the remaining $120 million available in the form of delayed draw term loans, which may be used to fund certain permitted acquisitions by WMLP until December 2015. Additionally, there is an accordion feature that takes effect when the delayed draw term loan feature expires which makes a further $150 million available for use to fund acquisitions during the remaining three years until the maturity of the WMLP Loan. Although the WMLP Loan will be consolidated in our financial statements due to our ownership of the GP and controlling interest in WMLP, neither Westmoreland nor any of its restricted subsidiaries will be obligors under the WMLP Financing Agreement and the WMLP Loan will be non-recourse to Westmoreland and its wholly owned subsidiaries.

If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify. On January 23, 2014, Moody’s Investors Service (“Moody’s”) concluded its review of our ratings which was initiated on December 26, 2013, following the announcement of our acquisition of the Canadian Subsidiaries, and confirmed our

33

existing credit ratings. In November 2014, both Moody’s and Standard & Poor’s Ratings Service raised our credit rating. However, we cannot assure you that rating agencies will not downgrade the credit ratings of our long-term senior secured debt in the future. Any such downgrade, or any perceived decrease in our creditworthiness, could impede our ability to refinance our existing debt, secure new debt or otherwise increase our future cost of borrowing and could create additional concerns on the part of our customers, partners and investors about our financial condition and results of operations.

If we fail to comply with certain covenants in our various debt arrangements, it could negatively affect our liquidity and ability to finance our operations.

Our lending arrangements contain, among other terms, events of default and various affirmative and negative covenants. Should we be unable to comply with any future debt-related covenant, we will be required to seek a waiver of such covenant to avoid an event of default. Covenant waivers and modifications may be expensive to obtain, or, potentially, unavailable. If we are in breach of any covenant and are unable to obtain covenant waivers and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.

We may not generate sufficient cash flow at our operating subsidiaries to pay our operating expenses, meet our debt service costs and pay our heritage and corporate costs.

Our ability to fund our operations and to make scheduled payments on our indebtedness will depend on our ability to generate cash in the future. Our historical financial results have been, and we expect our future financial results to be, subject to substantial fluctuations, and will depend upon general economic conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal and interest on the 8.75% Notes, the Term Loan or our other indebtedness.

If our cash flow and capital resources are insufficient to meet our debt service obligations or to fund our other liquidity needs, we may need to refinance all or a portion of our debt before maturity, seek additional equity capital, reduce or delay scheduled expansions and capital expenditures or sell material assets or operations. We cannot assure you that we would be able to refinance or restructure our indebtedness, obtain equity capital or sell assets or operations on commercially reasonable terms or at all. In addition, the terms of existing or future debt instruments may limit or prevent us from taking any of these actions. Our inability to take these actions and to generate sufficient cash flow to satisfy our debt service and other obligations could have a material adverse effect on our business, financial condition, results of operations and prospects.

If we cannot make scheduled payments on our debt or are not in compliance with our covenants and are not able to amend those covenants, we will be in default and holders of the 8.75% Notes and the lenders under the Term Loan and the Revolving Credit Facility could declare all outstanding principal and interest to be due and payable, the lenders under the Revolving Credit Facility could terminate their commitments to loan money to us, the holders of the 8.75% Notes and the lenders under the Term Loan and the Revolving Credit Facility could foreclose on the assets securing our debt to them and we could be forced into bankruptcy or liquidation. If we are not able to generate sufficient cash flow from operations, we may need to seek an amendment to the Indenture, the Term Loan Credit Agreement or the Revolving Credit Facility Agreement prevent us from potentially being in breach of our covenants. Such amendments, waivers or other modifications to our debt instruments may be expensive to obtain or potentially unavailable. If we are unable to obtain such an amendment, waiver or other modification, and our lenders accelerate our debt, we could attempt to refinance the debt or repay the debt by selling assets and applying the proceeds from such sales to the debt. Sales of assets undertaken in response to such immediate needs may be prohibited under our lending arrangements without the consent of our lenders, may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.

As a mine mouth operator, we provide coal to a small group of customers. This dependence could adversely affect our revenues if such customers reduce or suspend their coal purchases or if they become unable to pay for our coal.

In 2014, our Coal U.S. - Segment derived approximately 62.7% of its total revenues from coal sales to five power plants: Colstrip Units 3&4 (17.6%), Naughton Power Station (14.0%), Limestone Generating Station (13.8%), Colstrip Units 1 & 2 (10.9%) and Coyote Station (6.4%). In 2014, our Coal - Canada Segment derived approximately 54.8% of its total revenues from coal sales to two customers: SaskPower (37.2%) and ATCO (17.6%). Interruption in the purchases of coal by our principal customers could significantly affect our revenues. Unscheduled maintenance outages or other outages at our customers’ power plants, unseasonably moderate weather, higher-than-anticipated hydro seasons or increases in the production of alternative clean-energy generation such as wind power, or decreases in the price of competing fossil fuels such as natural gas, could cause our customers to reduce their purchases. Ten of our twelve mines are dedicated to supplying customers located

34

adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Additionally, certain of our long-term contracts are set to expire in the next several years. Our contracts with the Sherburne County Station are three-year rolling contracts, with one-third of the tonnage expiring on an annual basis. Our contract with Coyote Station, located adjacent to our Beulah mine and averaging approximately 2.5 million tons of coal sold per year, expires in May 2016 and is not expected to be renewed. Our contract with Colstrip Units 3 & 4 expires in December 2019. Should we be unable to successfully renew any or all of these expiring contracts, the reduction in the sale of our coal would adversely affect our operating results and liquidity and could result in significant impairments to the affected mine should the mine be unable to execute a new long-term coal supply agreement. The long term agreements we acquired or subsequently negotiated in connection with the Canadian Acquisition have long-remaining terms with the exception of the contract applicable to Poplar River Mine, which is set to expire in 2015. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Such agreements may also prohibit us from passing certain increased costs resulting from changes in regulations to our customers. Additionally, many of our coal supply agreements contain provisions allowing customers to suspend acceptance of coal shipments if coal delivered does not meet certain quality thresholds.

Similarly, interruption in the purchase of power by DNCP could also negatively affect our revenues. During the year ended December 31, 2014, the sale of power by ROVA to DNCP accounted for approximately 8% of our consolidated revenues. Although ROVA supplies power to DNCP under long-term power purchase agreements, if DNCP is unable or unwilling to pay for the power produced by ROVA in a timely manner, it could have a material adverse effect on our results of operations, financial condition, and liquidity.

WMLP also sells a material portion of its coal under supply contracts. For the year ended December 31, 2014, approximately 96.8% of WMLP's coal production was sold under long-term supply contracts. When WMLP’s current contracts with customers expire, its customers may decide not to extend existing contracts or enter into new contracts. In each of 2014 and 2015, 1.7 million tons are to be priced based on market indices, and in each of 2015, 2016 and 2017, 2.1 million tons are dependent upon reaching agreement during reopener periods.

Price adjustment, “price re-opener” and other similar provisions in WMLP’s supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect WMLP’s business, financial condition and/or results of operations.

For the year ended December 31, 2014, WMLP derived 99.1% of its total revenues from coal sales to its 10 largest customers (including their affiliates), with its top three customers (including their affiliates) accounting for 87.5% of such revenues. In the absence of long-term contracts, WMLP’s customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, which would negatively affect WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.

Our hedging arrangement in connection with the ROVA Consolidated Agreement may result in losses if the market price for power drops below the level of our hedged position.

Under the Consolidated Agreement with respect to our ROVA facility, we expect to forego dispatching the ROVA units in low demand periods and maintain them in idle status. During such low demand periods, we will meet DNCP’s power needs with fixed-price purchased power if doing so is more economically attractive than our physically operating the ROVA plants to generate power. Alternatively, we have the option to operate the ROVA plants, sell our produced power to DNCP and resell the fixed-price purchased power in the open market. If we choose to operate the ROVA plants and resell our fixed price purchased power into the open market, any such resales would be made at prevailing market rates. In the event that the prevailing market price for power falls below the level of our hedged position during periods when we are reselling the fixed price purchased power in the open market, those resales would result in losses to us. For the year ended December 31, 2014, we incurred losses related to these hedging arrangements of $31.1 million. Based on current market pricing trends, we expect to experience losses from time to time under these hedging arrangements when the market price for power is not commensurate with our hedged position.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If this occurs, we may decide to sell the customer’s coal on the spot market, which may be at prices lower

35

than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

In addition, WMLP sells some of its coal to brokers who may resell its coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, WMLP has contractual privity only with the brokers and may not be able to pursue claims against the end users. The bankruptcy or financial deterioration of any of WMLP’s customers, whether an end user or a broker, could adversely affect WMLP’s business, financial condition and/or results of operations.

Volatility in the equity markets or interest rate fluctuations could substantially increase our pension funding requirements and negatively impact our financial position.

At December 31, 2014, the projected benefit obligation under our defined benefit pension plans was $207.0 million and the fair value of plan assets was $160.9 million. The difference between plan obligations and assets, or the funded status of the plans, significantly affects the net periodic benefit cost and ongoing funding requirements of those plans. Among other factors, changes in interest rates, mortality rates, early retirement rates, investment returns and the market value of plan assets can affect the level of plan funding, cause volatility in the net periodic benefit cost and increase our future funding requirements. During the fiscal year ended 2014, we made $4.8 million in contributions to these pension plans and accrued $5.4 million in expenses related thereto. The current economic environment increases the risk that we may be required to make even larger contributions in the future.

If our assumptions regarding our future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed. In addition, we may have exposure under those plans that extend beyond what our obligations would be with respect to our own employees.

We provide various postretirement medical benefits and workers’ compensation benefits to current and former employees and their dependents. We calculate the total accumulated benefit obligations according to guidance provided by GAAP. We estimate the present value of our postretirement medical, black lung and workers’ compensation benefit obligations to be $306.4 million, $14.0 million and $7.0 million, respectively, at December 31, 2014. In respect of our Canadian Operations we have an obligation to provide postretirement health coverage for eligible current union employees, as described in greater detail below. We have estimated these unfunded obligations based on actuarial assumptions and if our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially different.

Moreover, regulatory changes could increase our obligations to provide these or additional benefits. We participate in defined benefit multi-employer funds that were established in connection with the Coal Act, which provides for the funding of health and death benefits for certain UMWA retirees. Our contributions to these funds totaled $2.0 million and $2.2 million for the years ended December 31, 2014 and 2013, respectively. Our contributions to these funds could increase as a result of a shrinking contribution base as a result of the insolvency of other coal companies that currently contribute to these funds, lower than expected returns on fund assets or other funding deficiencies.

We could also have obligations under the Tax Relief and Health Care Act of 2006, ("2006 Act"). The 2006 Act authorized up to a maximum of $490 million in federal contributions to pay for certain benefits, including the healthcare costs under certain funds created by the Coal Act for “orphans,” i.e. retirees from companies that subsequently ceased operations, and their dependents. However, if Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, we, along with other contributing employers and certain affiliates, would be responsible for the excess costs.

We also contribute to a multi-employer defined benefit pension plan, the Central Pension Fund of the Operating Engineers, ("Central Pension Fund") on behalf of employee groups at our Rosebud, Absaloka and Savage mines that are represented by the International Union of Operating Engineers. The Central Pension Fund is subject to certain funding rules contained in the Pension Protection Act of 2006 ("PPA"). Under the PPA, if the Central Pension Plan fails to meet certain minimum funding requirements, it would be required to adopt a funding improvement plan or rehabilitation plan. If the Central Pension Fund adopted a funding improvement plan or rehabilitation plan, we could be required to contribute additional amounts to the fund. As of January 31, 2014, its last completed fiscal year, the Central Pension Fund reported that it was underfunded. If we were to partially or completely withdraw from the fund at a time when the Central Pension Fund were underfunded, we would be liable for a proportionate share of the fund’s unfunded vested benefits, and this liability could have a material adverse effect on our financial position.

Through our Canadian Operations we have responsibility for obligations under certain pension plans related to certain of the acquired operations. We have evaluated these plans, and believe that certain of them may be underfunded by immaterial amounts.

36

We are obligated to make contributions to these plans based upon agreement with the plan members and collective bargaining agreements with the representative unions. Our future contributions to these defined benefit plans are made in accordance with applicable pension legislation and the Income Tax Act (Canada). Further contributions to the pension plans could be required based on actuarial valuations, agreements, the plan asset investment performance, and future legislated requirements.

Under Canadian provincial Workers’ Compensation legislation, we remain obligated to fund workers’ compensation benefits arising from workplace injuries, disease and death of current and former employees. This obligation is based on premiums assessed by the applicable Workers’ Compensation Board which may vary based on the claims experience of the employer. We may be required to contribute additional premiums in the future depending on the number and amount of claims.

Our reserve estimates may prove to be incorrect.

The coal reserve estimates in this report are estimates based on the interpretation of limited sampling and subjective judgments regarding the grade, continuity and existence of mineralization, as well as the application of economic assumptions, including assumptions as to operating costs, foreign exchange rates and future commodity prices. The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of ore bodies or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves.

Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

• quality of the coal;

• geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

• the percentage of coal ultimately recoverable;

• the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

• economic assumptions, including assumptions as to foreign exchange rates and future commodity prices;

• assumptions concerning the timing for the development of the reserves; and

• assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

We are subject to stringent reclamation and closure standards for our mining operations. We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate. Likewise, if our customers, some of

37

whom are contractually obligated to pay certain reclamation costs, default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation.

We estimate that our gross reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $452.7 million (on a present value basis) at December 31, 2014. Of these December 31, 2014 liabilities, our customers have assumed $116.5 million by contract. In addition, we held final reclamation deposits, received from customers, of approximately $77.9 million at December 31, 2014 to provide for these obligations. We estimate that our obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits was $261.0 million at December 31, 2014. We must recover this $261.0 million from revenues generated by coal sales.

Although we update our estimated costs annually, our recorded obligations may prove to be inadequate due to changes in legislation or standards and the emergence of new restoration techniques. Furthermore, the expected timing of expenditures could change significantly due to changes in commodity costs or prices that might curtail the life of an operation. These recorded obligations could prove insufficient compared to the actual cost of reclamation. Any underestimated or unidentified close down, restoration or environmental rehabilitation costs could have an adverse effect on our reputation as well as our asset values, results of operations and liquidity.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.

We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. We anticipate that, as we permit additional areas for our mines, our bonding and collateral requirements could increase. Any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. Our results of operations could be negatively affected if the cost of our reclamation bonding premiums and collateral requirements were to increase. Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas, which would hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues. 

Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.

With the exception of our recently acquired Buckingham Mine, our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include: unplanned equipment failures; geological, hydrological or other conditions such as variations in the quality of the coal produced from a particular seam; variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; weather conditions; and competition and/or conflicts with other natural gas resource extraction activities and production within our operating areas. For example, in our recent past, we have endured poor rail performance at the Absaloka Mine, and Coal Valley Mine, a major blizzard at the Beulah Mine, a trestle fire at the Beulah Mine, and an unanticipated replacement of boom suspension cables on one of our draglines, all of which interrupted deliveries. Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines.

In addition, unplanned outages of draglines and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time and are an inherent risk of our coal mining business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. As of December 31, 2014, six of our 30 owned or operated draglines were not in use due to either equipment servicing or because the dragline was scheduled to be down based on the operational needs of our mines. If properly maintained, a dragline can operate for 40 years or longer. As of December 31, 2014, the average age of Westmoreland’s dragline fleet was 34 years. In addition, at our Kemmerer Mine we use shovels instead of draglines. If properly maintained, a shovel can last for 30 years or longer. As of December 31, 2014, the average age of our shovels was 17 years. As our draglines, shovels and other major equipment ages, we may experience unscheduled maintenance outages or increased maintenance costs, which would adversely affect our operating results.

Unplanned outages and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time at our power plant customers and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues because of selling fewer tons of coal. For example, in November 2011, the Sherburne County station experienced an explosion and fire that caused an extended outage. As a result,

38

we lost approximately 50% of our coal sales in 2012 and 2013 at our Absaloka Mine. While the Sherburne County station initially indicated a start-up date of March 2013, it did not ultimately resume operations until October 2013, resulting in additional lost coal sales during 2013. We maintain business interruption insurance coverage to lessen the impact of events such as this, and have received a total of approximately $33.6 million of cash proceeds in insurance compensation for lost sales to the Sherburne County station. While we believe our insurance did not fully compensate us for the impact of lost sales, we believe the shortfall was not material. However, business interruption insurance may not always provide adequate compensation for lost coal sales, and significant unanticipated outages at our power plant customers which result in lost coal sales could result in significant adverse effects on our operating results.

Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.

Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.

The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As WMLP’s mines in these regions become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. These factors could adversely affect WMLP’s business, financial condition and/or results of operations and its ability to make distributions to unit holders like us.

Long-term sales and revenues could be significantly affected by environmental regulations and the effects of the environmental lobby.

Environmental regulations that are becoming increasingly stringent, as well as increased pressure from environmental activists, may reduce demand for our products. For example, a consortium of environmental activists is actively pushing to shut down one-third of the nation’s coal plants by 2020. They are taking particular interest in Colstrip Units 1 and 2 and are actively lobbying the EPA to require cost-prohibitive pollution control equipment. In litigation filed in 2012, the activists stated that the EPA’s Best Available Retrofit Technology (“BART”) analysis for regional haze provides support for a determination that additional controls are necessary to achieve BART. A decision in the case is pending. In 2013, environmental groups also filed a citizen suit complaint in Montana district court asserting that the owners and operators of Colstrip are in violation of Clean Air Act requirements. Trial in the case has been reset for August 2015. If environmental groups are successful, Colstrip would be required to undergo new permitting and comply with more stringent emission limits applicable to a number of pollutants. If additional emissions controls and upgrades are required at Colstrip Units 1 and 2, it is possible the owners could elect to shut down the units in lieu of making the large capital expenditures required to comply. If such a decision were made, we could lose coal sales of approximately 3.0 million tons per year. The loss of the sale of this tonnage at our Rosebud Mine could have a material adverse effect on the mine’s revenues and profitability.

Additionally, Rocky Mountain Power, the owner of the Naughton Power Station located adjacent to our Kemmerer Mine, which is our Kemmerer Mine’s primary customer, has sought regulatory approval to convert Unit 3 at Naughton to 100% natural gas fueling. When complete, the conversion of Unit 3 to natural gas will result in the loss of coal sales at our Kemmerer Mine. However, Rocky Mountain Power recently announced the conversion of Naughton Unit 3 will not occur until 2018. In addition, price protections built into the contract that are in effect from 2017 to 2021 will partially offset the effects of lowered

39

volume following the conversion of Unit 3. Despite these price protections, the lost sales at the Kemmerer Mine could have a material adverse effect on the mine’s revenues and profitability and on our operating results. Additional power plants that buy our coal may be considering or may consider in the future fuel source conversion or decreased operations in order to avoid costly upgrades of pollution control equipment, and such steps, if taken, could result in a reduced demand for our products and materially and adversely affect our revenues and profitability.

The EPA and the U.S. Army Corps of Engineers have proposed a rule to clarify which waters and wetlands are subject to regulation under the CWA. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs.

The EPA has executed a final rule relating to the disposal of CCR from electric utilities. The changes to the management of CCR could increase our and our customers’ operating costs and reduce sales of coal.

We are also affected by Canadian GHG emissions regulations. On September 12, 2012, the federal government of Canada released final regulations for reducing GHG emissions from coal-fired electricity generation: “Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity” (the “Canadian CO2 Regulations”). The Canadian CO2 Regulations will require certain Canadian coal-fired electricity generating plants, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 420 tons of CO2 per gigawatt hour. The impact of the Canadian CO2 Regulations on existing plants will vary by province and specific location. PMRU’s long-term sales could be reduced unless certain existing plants that it supplies or new plants built to replace such existing plants are equipped with carbon capture and sequestration or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard.

In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to reliably estimate the extent to which such regulations will impact the operations we acquired in the Canadian Acquisition. However, our Canadian Operations involve large facilities, so the setting of emissions targets (whether in the manner described above or otherwise) may well affect some or all of our Canadian customers, and may in turn have a material adverse effect on our business, results of operations and financial performance. In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or an increase in cost of the fuels used in power production (including coal, oil and gas or other products) may also add to our operating costs.

A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.

We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

We are dependent on information technology and our systems and infrastructure face certain risks, including cybersecurity risks and data leakage risks.

We are dependent on information technology systems and infrastructure. Any significant breakdown, invasion, destruction or interruption of these systems by employees, others with authorized access to our systems, or unauthorized persons could negatively impact operations. There is also a risk that we could experience a business interruption, theft of information, or reputational damage as a result of a cyber-attack, such as an infiltration of a data center, or data leakage of confidential information either internally or at our third-party providers. While we have invested in the protection of our data and information technology to reduce these risks and periodically test the security of our information systems network, there can be no assurance that our efforts will prevent breakdowns or breaches in our systems that could adversely affect our business.

40

Our Absaloka Mine benefited from Indian Coal Production Tax Credits, the permanent loss of which will adversely affect the financial condition of the operation.

The ICTC, which our Absaloka Mine historically benefited from, expired on December 31, 2014. There is no assurance that a renewal, if any is enacted, would be enacted with retroactive effect. The provisions regarding any future renewal may not be as favorable as those that previously existed. Additionally, the investment in Absaloka by our partner did not continue after December 31, 2013. We expect to seek a new partner in the event of a future renewal, but our results of operations will continue to be negatively affected during the interim period and for any period for which the ICTC is not renewed with retroactive effect. From 2009 through 2013, we experienced a yearly average of $3.1 million of income and $6.1 million of cash receipts from Absaloka’s participation in ICTC transactions.

Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable and to raise the capital necessary to fund our expansion.

Our recoverable reserves decline as we produce coal. We have not yet applied for the permits to use all of the coal deposits under our mineral rights, and the government agencies may not grant those permits in a timely manner or at all. Furthermore, we may not be able to mine all of our coal deposits as efficiently as we do at our current operations. Our future success depends upon conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations, or financing activities, or both. As we mine our coal and deplete our existing reserves, replacement reserves may not be available when required or, if available, we may not be capable of mining the coal at costs comparable to those characteristic of the depleting mines. These factors could have a material adverse effect on our mining operations and costs, and our customers’ ability to use the coal we mine.

We may not be able to successfully replace our reserves or grow through future acquisitions.

In recent years, we have expanded our operations by adding new mines and reserves through strategic acquisitions, and we intend to continue expanding our operations and coal reserves through additional future acquisitions. Our future growth could be limited if we are unable to continue making acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Our ability to make acquisitions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Transportation impediments may hinder our current operations or future growth.

Certain segments of our current business, principally our Absaloka Mine and our Coal Valley Mine rely on rail transportation for the delivery of coal product to customers and ports. Our ability to deliver our product in a timely manner could be adversely affected by the lack of adequate availability of rail capacity, whether because of work stoppages, union work rules, track conditions or otherwise. In 2011, flooding conditions disrupted rail service to the Absaloka Mine, resulting in lost revenue. Rail or shipping transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is a key factor in a customer’s purchasing decision. In addition, the Coal Valley Mine exports the majority of its production to the global seaborne market through port facilities in western Canada.

The unavailability of rail capacity and port capacity could also hinder our future growth as we seek to sell coal into new markets. The current availability of rail cars is limited and at times unavailable because of repairs or improvements, or because of priority transportation agreements with other customers. Port capacity is also restricted in certain markets. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail or port capacity would hamper our future growth. We currently have sufficient committed port capacity to operate our export business, and additional port capacity is expected to be constructed in western Canada in the future. However, increases in transportation costs or the lack of sufficient rail or port capacity or availability could make our coal less competitive, or could result in coal becoming a less competitive source of energy in general, which could lead to reduced coal sales and/or reduced prices we receive for the coal. Our inability to timely deliver product or fuel switching due to rising transportation costs could have a material adverse effect on our business, financial condition and results of operations.

In addition, WMLP depends upon barge, rail and truck systems to deliver coal to its customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair WMLP’s ability to supply coal to its customers. In recent years, the Commonwealth of Kentucky and the State of West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in

41

which WMLP’s coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs, which could have an adverse effect on WMLP’s ability to increase or to maintain production and could adversely affect its revenues.

Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. Some materials, such as steel, are needed to comply with regulatory requirements. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.

Our long-term coal contracts are "cost protected" in that they typically contain either full pass-through of our costs or price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs.

WMLP enters into forward-purchase contract arrangements for a portion of its anticipated diesel fuel and explosive needs. Additionally, some of WMLP’s expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of its customers, that allow for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter. While WMLP’s strategy provides it protection in the event of price increases to its diesel fuel, it may also prevent WMLP from the benefits of price decreases. If prices for diesel fuel decreased significantly below WMLP’s forward-purchase contracts, it would lose the benefit of any such decrease.

Our ability to acquire new mineral titles in certain Canadian provinces may be affected by aboriginal rights, and such rights may give rise to claims that compete with or impair our title to certain of our Canadian properties.

Canadian courts have recognized that aboriginal peoples may have rights with respect to land used or occupied by their ancestors in the absence of treaties to address those rights. These aboriginal rights may vary from limited rights of use for traditional purposes to rights of title and will depend upon, among other things, the nature and extent of prior aboriginal use and occupation. Aboriginal peoples may also have rights under applicable treaties for harvesting and ceremonial purposes on Crown lands or lands to which they have rights of access. The provincial governments of Alberta and Saskatchewan, as well as the Canadian government, are required to consult with aboriginal peoples with respect to the granting of mineral rights and the issuance or amendment of project authorizations, including approvals, permits and licenses. These requirements may affect the ability of our Canadian Subsidiaries to acquire effective mineral titles in these jurisdictions within a reasonable time frame, and may affect our development schedule and costs of mineral properties. Additionally, the risk of unforeseen aboriginal title claims could compete with or impair some or all of our Canadian Operations

Union represented labor creates an increased risk of work stoppages and higher labor costs.

As of December 31, 2014, approximately 60% of our total U.S. workforce is represented by two labor unions, the International Union of Operating Engineers and the UMWA. Our unionized workforce is spread out amongst the majority of our surface mines. As a majority of our workforce is unionized, there may be an increased risk of strikes and other labor disputes, and our ability to alter labor costs is subject to collective bargaining. The collective bargaining agreement relating to the represented workforce at the Absaloka Mine will expire on May 31, 2015. In 2012, we were successful in entering into agreements with our workforce at Savage, Kemmerer and Rosebud. If our Jewett Mine operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations. We reached an  with the UMWA in December 2014 on a new collective bargaining agreement at the Beulah Mine to replace the existing agreement which expires on January 1, 2015. While strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short time could have a material adverse effect on our financial results.

Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if

42

the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized.

As of December 31, 2014, approximately 69% of our total Canadian workforce was represented by a labor union. There are labor agreements in place with one or more unions at each of the producing mines we acquired in the Canadian Acquisition, other than the Genesee Mine. Our collective bargaining agreement related to the Estevan Mine will expire on June 30, 2015. If we are not successful in negotiating new labor agreements as they expire with any of the Canadian workforce unions or otherwise maintaining strong partnerships with them, it could result in labor disputes, work stoppages or higher labor costs, any of which could have an adverse effect on our business and results of operations.

Currently, none of WMLP’s employees is represented under collective bargaining agreements. However, all of its workforce may not remain union-free in the future. If some or all of WMLP’s workforce were to become unionized, it could adversely affect its productivity and labor costs and increase the risk of work stoppages, all of which could adversely affect WMLP’s business, financial condition and/or results of operations.

We face intense competition to attract and retain employees.

We are dependent on retaining existing employees and attracting additional qualified employees to meet current and future needs. We face intense competition for qualified employees, and there can be no assurance that we will be able to attract and retain such employees or that such competition among potential employers will not result in increasing salaries. We rely on employees with unique skill sets to perform our mining operations, including engineers, mechanics and other highly skilled individuals. An inability to retain existing employees or attract additional employees, especially with mining skills and background, could have a material adverse effect on our business, cash flows, financial condition and results of operations.

As a result of the Canadian Acquisition, we are subject to foreign exchange risk as a result of exposures to changes in currency exchange rates between the U.S. and Canada.

As a result of the Canadian Acquisition, we face increased exposure to exchange rate fluctuations between the Canadian dollar and U.S. dollar. We realize a large portion of our revenues from sales made from the Canadian assets in Canadian dollars, and almost all of the expenses incurred by the Canadian assets are recognized in Canadian dollars. The exchange rate of the Canadian dollar to the U.S. dollar has been at or near historic highs in recent years but in the last quarter of 2014 and first quarter of 2015 has weakened considerably. If this weakening of the Canadian dollar in comparison to the U.S. dollar continues, earnings generated from our Canadian Operations will translate into reduced earnings in our consolidated statements of operations reported in U.S. dollars. In addition, our Canadian Subsidiaries also record certain accounts receivable and accounts payable, which are denominated in Canadian dollars. Foreign currency transactional gains and losses are realized upon settlement of these assets and obligations.

Fluctuations in the U.S. dollar relative to the Canadian dollar may make it more difficult to perform period-to-period comparisons of our reported results of operations. For purposes of accounting, the assets and liabilities of our Canadian Operations will be translated using period-end exchange rates, and the revenues and expenses of our Canadian Operations will be translated using average exchange rates during each period. Translation gains and losses are reported in accumulated other comprehensive loss as a component of stockholders’ equity.

Federal legislation could result in higher healthcare costs.

In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.

Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.

Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.

43

Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.

                Among the changes contained in President Obama’s budget proposal (the “Budget Proposal”) is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.

Risk Factors Relating to the Coal and Power Industries

The risk of prolonged recessionary conditions could adversely affect our financial condition and results of operations.

Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity. Recent economic uncertainty has raised the risk of prolonged recessionary conditions. Historically, global demand for basic inputs, including electricity production, has decreased during periods of economic downturn. If demand for electricity production decreases, our financial condition and results of operations could be adversely affected.

Competition in the North American coal industry may adversely affect our revenues and results of operations.

A few of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our future revenues and results of operations. Among other things, competitors could develop new mines that compete with our mines, have higher quality coal than our mines or build or obtain access to rail lines that would adversely affect the competitive position of our mines.

Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce or the prices that we receive.

In addition to competing with other coal producers, we compete generally with producers of other fuels. In 2014, the electric utility industry accounted for the majority of coal consumption in the U.S. and Canada. The demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, hydro, natural gas and fuel oil as well as alternative sources of energy affects the amount of coal consumed by the electric utility industry. A decrease in coal consumption by the electric utility industry could adversely affect the demand for, and price of, coal, which could negatively impact our results of operations and liquidity. We do not have contracts guaranteeing the purchase of fixed quantities of coal, so revenue can fall even though we have long-term contracts.

Some power plants are fueled by natural gas because of the relatively lower construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel. In addition, some states have adopted or are considering legislation that encourages domestic electric utilities to switch from coal-fired power generation plants to natural gas powered plants. Similar legislation has been implemented or is under consideration in several Canadian provinces. Passage of these and other state, provincial or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal, state or provincial governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.

Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods due to extraction techniques involving horizontal drilling and hydraulic fracturing that have led to economic access to large quantities of natural gas in the United States and Canada, making it an attractive competing fuel. A continuing decline in the price of natural gas, or continuing periods of sustained low natural gas prices, could cause demand for coal to decrease, result in fuel switching and decreased coal consumption by electricity-generating utilities and adversely affect the price of our coal. Sustained low natural gas prices may cause utilities to phase-out or close existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal.

44

Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.

Although our mines and the majority of our customers are located in North America, we compete in a worldwide market for coal and coal products. The pricing and demand for our products is affected by a number of global economic factors that are beyond our control and difficult to predict. These factors include:

• currency exchange rates;

• growth of economic development;

• price of alternative sources of electricity or steel;

• worldwide demand for coal and other sources of energy; and

• ocean freight rates.

Any decrease in the aggregate amount of coal exported from the United States and Canada, or any increase in the aggregate amount of coal imported into the United States and Canada, could have a material adverse impact on the demand for our coal, our pricing and our profitability. Ongoing uncertainty in European economies and slowing economies in China, India and Brazil have reduced and may continue to reduce near-term pricing and demand for coal exported from the United States and Canada. Coal Valley Mine primarily supplies premium thermal coal to the Asian export market. Ownership of this mine will increase our exposure to price fluctuations in the international coal market, and a substantial downturn in demand in the Asian market could have a material adverse effect on our financial condition and results of operations.

Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

• limitations on land use;

• employee health and safety;

• mandated benefits for retired coal miners;

• mine permitting and licensing requirements;

• reclamation and restoration of mining properties after mining is completed;

• air quality standards;

• discharges to water;

• construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;

• protection of human health, plant life and wildlife;

• management of the materials generated by mining operations and discharge of these materials into the environment;

• effects of mining on groundwater quality and availability; and

• remediation of contaminated soil, surface and groundwater.

We are required to prepare and present to governmental authorities data concerning the potential effects of any proposed exploration or production of coal on the environment and the public has statutory rights to submit objections to requested permits and approvals. Failure to comply with MSHA regulations may result in the assessment of administrative, civil and criminal penalties. Other governmental agencies may impose cleanup and site restoration costs and liens, issue injunctions to limit or cease operations, suspend or revoke permits and take other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. We must compensate employees for work-related injuries. If we do not make adequate provision for our workers’ compensation liabilities, it could harm our future operating results. If we are pursued for any sanctions, costs and liabilities, our mining operations and, as a result, our results of operations, could be adversely affected.

United States and Canadian federal, state or provincial regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing of our mines, our coal sales contracts may permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, and

45

potentially at prices higher than our cost to produce coal, to fulfill these obligations, and negotiate settlements with customers, which may include price and quantity reductions, the extension of time for delivery, or contract termination. Additionally, we may be required to incur capital expenditures to re-open the mine. These actions could adversely affect our business, financial condition and/or results of operations.

New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and results of operations. For additional information regarding specific regulations that impact our operations, see “U.S. and Canadian Coal Segment - Material Effects of Regulation.”

Concerns regarding climate change are, in many of the jurisdictions in which we operate, leading to increasing interest in, and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.

GHG emissions have increasingly become the subject of international, national, state, provincial and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our products or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the EPA has issued a determination that emissions of carbon dioxide, methane, nitrous oxide and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA implemented GHG-related reporting and permitting rules. Portions of the EPA’s GHG permitting rules, which were the subject of litigation by some industry groups and states, were recently struck down in part by the U.S. Supreme Court, but the EPA’s authority to impose GHG control technologies on a majority of large emissions sources, including coal-fired electric utilities, remain in place. President Obama in June 2013 announced a Climate Action Plan, which included a Presidential Memorandum directing the EPA to issue standards for GHG emissions from existing, modified and reconstructed fossil-fuel fired power plants. The EPA issued a revised proposal with standards for new fossil fuel-fired plants, including coal-fired plants, in September 2013, which the EPA plans to finalize by January 2015. The EPA also has released its “Clean Power Plan” in June 2014, which includes proposed standards for existing and modified sources. Under the Clean Power Plan as currently proposed, the EPA would set standards for existing sources as stringent state-specific carbon emission rates that, if finalized, would be phased in between 2020 and 2030. The proposed rule would give states the discretion to use a variety of approaches - including cap-and-trade programs - to meet the standard. The EPA estimates that the proposed existing source rule would reduce CO2 emissions from the power sector by 30 percent by 2030, with a focus on emissions from coal-fired generation. The EPA plans to finalize the rule by June 2015, with state plans due by June 2016, with one- to two-year extensions available. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these proposed rules would have on our revenues and profitability. For additional information, see “Business - Material Effects of Regulation” in this report.

In Canada, in September 2012 the federal government released final regulations for reducing GHG emissions from coal-fired electricity generation through the Canadian CO2 Regulations. The Canadian CO2 Regulations will require certain Canadian coal-fired electricity generating units, effective July 1, 2015, to achieve an average annual emissions intensity performance standard of 420 tons of CO2 per gigawatt hour. This performance standard represents approximately one-half of the annual average CO2 emissions intensity of the customer generating assets currently served by the Prairie operations. The performance standard will apply to new units commissioned after July 1, 2015 and to units that are considered to have reached the end of their useful life, generally between 45 and 50 years from the unit’s commissioning date. New and end-of-life units that incorporate technology for carbon capture and sequestration may apply for a temporary exemption from the performance standard that would remain in effect until 2025, provided that certain implementation milestones are met. Provincial equivalency agreements, under which the Canadian CO2 Regulations would stand down, are being negotiated or discussed with the provinces of Alberta and Saskatchewan. The Prairie coal production in the long-term could be reduced unless certain existing units or new units of the customers served by the Prairie operations are equipped with carbon capture and storage or other technology that achieves the prescribed performance standard, the impact of the Canadian CO2 Regulations is altered by equivalency agreements, or the Canadian CO2 Regulations are changed to lower the performance standard. The impact of the Canadian CO2 Regulations on existing units will vary by location and province.

46

In addition, various Canadian provincial governments and other regional initiatives are moving ahead with GHG reduction and other initiatives designed to address climate change. For example, under the Climate Change and Emissions Management Act (the “CCEM”), the Province of Alberta enacted the “Specified Gas Emitters Regulation.” As of January 1, 2008, this enactment requires certain existing facilities with direct emissions of 100,000 tons or more of certain specified gases to ensure that the net emissions intensity for a year for an established facility must not exceed 88% of the baseline emissions intensity for the facility. For the 2013 compliance period, Coal Valley Mine exceeded the 100,000 ton emissions threshold established under the Specified Gas Emitters Regulation, and Coal Valley Mine was required to contribute to the Climate Change and Emissions Management Fund. For the 2014 compliance period, the preliminary calculations indicate Coal Valley Mine will be required to purchase fund credits. It is anticipated that for the next several years, emissions intensity at Coal Valley Mine will increase as the distance between the coal being mined and the processing plant increases. The Government of Alberta has also introduced a complementary Specified Gas Reporting Regulation, which came into force on October 20, 2004. This legislation requires all industrial emitters emitting 50,000 tons or more of CO2 to report their annual GHG emissions in accordance with the specified Gas Reporting Standard published by the Government of Alberta. In Saskatchewan, Bill 126, The Management and Reduction of Greenhouse Gases Act, was passed in 2010 but is not yet proclaimed in force. The legislation provides a framework for the control of GHG emissions by regulated emitters and will be proclaimed once accompanying draft regulations are finalized.

As it is unclear at this time what shape additional regulation in Canada will ultimately take, it is not yet possible to estimate the extent to which such regulations will impact our Canadian Operations. However, those operations involve large facilities, so the setting of emissions targets (whether in the manner described above or otherwise) may well affect them and may have a material adverse effect on our business, results of operations and financial performance. These developments in both Canada and the United States could have a variety of adverse effects on demand for the coal we produce. For example, laws or regulations regarding GHGs could result in fuel switching from coal to other fuel sources by electricity generators, or require us, or our customers, to employ expensive technology to capture and sequester carbon dioxide. Political and environmental opposition to capital expenditure for coal-fired facilities could affect the regulatory approval required for the retrofitting of existing power plants. For example, the Naughton power facility, which is located adjacent to the Kemmerer Mine, announced in April 2012 that it is seeking regulatory approval to switch Unit 3 to natural gas from coal. The conversion of Naughton Unit 3 to natural gas would result in significant reduction in coal sales from our Kemmerer Mine, and could have a material adverse effect on our results of operations. However, Rocky Mountain Power, the owner of the Naughton facility, recently announced that the conversion will not take place until at least 2018. Political opposition to the development of new coal-fired power plants, or regulatory uncertainty regarding future emissions controls, may result in fewer such plants being built, which would limit our ability to grow in the future.

In addition to directly emitting GHGs, our Canadian Operations require large quantities of power. Future taxes on or regulation of power producers or the production of coal, oil and gas or other products may also add to our operating costs. And many of the developments in the U.S. discussed above that may affect our customers and demand for our coal could also affect us directly through adverse impacts on ROVA

An inability to obtain and/or renew permits necessary for WMLP’s operations could prevent it from mining certain of its coal reserves.

The slowing pace at which permits are issued or renewed for new and existing mines in WMLP’s area of operations has materially impacted production in Appalachia. Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and dredged or fill material into waters of the United States. WMLP’s surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by its mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in which WMLP operates. An inability to obtain the necessary permits to conduct WMLP’s mining operations or an inability to comply with the requirements of applicable permits could reduce WMLP’s production and cash flows, which could adversely affect its business, financial condition and/or results of operations and our cash flow.

47

Extensive environmental laws, including existing and potential future legislation, treaties and regulatory requirements relating to air emissions other than GHGs, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline, and could impose additional costs on ROVA.

Our customers, as well as ROVA, are subject to extensive environmental regulations particularly with respect to air emissions other than GHG. Coal contains impurities, including but not limited to sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The emission of these and other substances is extensively regulated at the federal, state, provincial and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal. For example, the purchaser of coal produced from the Jewett Mine blends our lignite with compliance coal from Wyoming. Tightened nitrogen oxide and new mercury emission standards could result in the customer purchasing an increased blend of the Wyoming coal in order to reduce emissions. Further, increased market prices for sulfur dioxide emissions allowances and increased coal ash management costs could also favor an increased blend of the lower ash Wyoming compliance coal. In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract. A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operations and financial condition.

The EPA intends to issue or has issued a number of significant regulations that will impose more stringent requirements relating to air, water and waste controls on electric generating units. These rules include the EPA’s executed new final rule for CCR management that further regulates the handling of wastes from the combustion of coal. In addition, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. This rule was upheld by the U.S. Court of Appeals for the D.C. Circuit in April 2014. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings, which are ongoing. The EPA issued an interim rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017. In May 2014, the EPA Administrator signed a final rule that establishes requirements for cooling water intake structures for the withdrawal of cooling water by electric generating plants; the rule is anticipated to affect over 500 power plants.

Considerable uncertainty is associated with air emissions initiatives. New regulations are in the process of being developed, and many existing and potential regulatory initiatives are subject to review by federal or state agencies or the courts. Stringent air emissions limitations are either in place or are likely to be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. For example, the owners of Units 3 and 4 at Colstrip, adjacent to our Rosebud Mine, are getting considerable pressure from environmental groups to install Selective Catalytic Reduction (“SCR”) technology. Should the owners be forced by the EPA to install such technology, the capital requirements could make the continued operation of the two units unsustainable. As a result, Colstrip and other similarly-situated power plants may switch to other fuels that generate fewer of these emissions or may install more effective pollution control equipment that reduces the need for low-sulfur coal. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new coal-fired power plants could have a material adverse effect on demand for, and prices received for, our coal. Alternatively, less stringent air emissions limitations, particularly related to sulfur, to the extent enacted, could make low-sulfur coal less attractive, which could also have a material adverse effect on the demand for, and prices received for, our coal.

The regulation of air emissions in Canada may also reduce the demand for the products of the operations we acquired in the Canadian Acquisition. Specifically, the Alberta Environmental Protection and Enhancement Act (“EPEA”) and the Canadian Environmental Protection Act, 1999 (“CEPA, 1999”) and the provision for the reporting of pollutants via the National Pollutant Release Inventory (“NPRI”), could also have a significant effect on the customers of our Canadian mines, which in turn could, over time, significantly reduce the demand for the coal produced from those mines.

The customers of our Canadian mines must comply with a variety of environmental laws that regulate and restrict air emissions, including the EPEA and its regulations, and the CEPA, 1999. Because many of these customers’ activities generate air emissions from various sources, compliance with these laws requires our customers in Canada to make investments in pollution control equipment and to report to the relevant government authorities if any emissions limits are exceeded or are made in contravention of the applicable regulatory requirements.

These laws restrict the amount of pollutants that our Canadian customer’s facilities can emit or discharge into the environment. The NPRI, for example, is created under authority of the CEPA, 1999 and is a Canada-wide, legislated, and publicly accessible inventory of specific substances that are released into the air, water, and land. The purpose of the NPRI was to provide comprehensive national data on releases of specified substances, and assists with, identifying priorities for action,

48

encouraging voluntary action to reduce releases, tracking the progress of reductions in releases, improving public awareness and understanding of substances released into the environment, and supporting targeted initiatives for regulating the release of substances.

Regulatory authorities can enforce these and other environmental laws through administrative orders to control, prevent or stop a certain activity; administrative penalties for violating certain environmental laws; and judicial proceedings. If environmental regulatory burdens continue to increase for our Canadian customers, as a result of policy changes or increased regulatory reform relating to the substances reported, it could potentially affect customer operations and future demand for coal.

Risk Factors Relating to our Equity

Provisions of our certificate of incorporation, bylaws, and Delaware law may have anti-takeover effects that could prevent a change of control of our company that stockholders may consider favorable, and the market price of our common stock may be lower as a result.

Provisions in our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to bring about some types of corporate actions such as electing individuals to the board of directors. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control. Provisions in the indenture governing the 8.75% Notes regarding certain change of control events could have a similar effect.

Risks Related to Our Acquisitions

We may not have uncovered all risks associated with our acquisition of the Canadian Subsidiaries, our controlling interest in WMLP or Buckingham (collectively, the “Acquisitions”) and significant liabilities of which we are not aware may exist now or arise in the future.

Upon consummation of the Acquisitions, we assumed the risk of unknown, and certain known, liabilities. We may become responsible for unexpected liabilities that we failed or were unable to discover in the course of performing due diligence in connection with the Acquisitions or for costs associated with known liabilities that exceed our estimates. Under the various purchase arrangement for relating to the Acquisitions, there may or may not be recourse to indemnification should we discover a previously unknown liability, whether material or immaterial.

WMLP may underperform relative to our expectations, causing our financial results to differ from our expectations or the expectations of the investment community, and we may not be able to achieve anticipated cost savings or other anticipated objectives of our acquisition of the GP.

The success of the WMLP transactions will depend, in part, on our ability to realize the anticipated growth opportunities and operating efficiencies, which we influence as the owner of the GP. The potential obstacles to realizing our expectations for the WMLP transactions include, among other things:

• failure to implement our strategy for the development and streamlining of WMLP’s business;

• failure to implement our dropdown strategy to transfer certain strategic assets or operations to WMLP in the future;

• unanticipated changes in commodity prices;

• unanticipated changes in applicable laws and regulations;

• retaining and obtaining required regulatory approvals, licenses and permits; and

• other unanticipated issues, expenses and liabilities.

Many of these factors will be outside of our control, and any one of them could result in increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially impact our business, financial condition and results of operations.

Our cash flow depends, in part, on the available cash and distributions of WMLP.

We expect our partnership interests in WMLP to be significant cash-generating assets. Therefore, our cash flow will be dependent, to some extent, upon the ability of WMLP to make quarterly distributions to its unitholders, including us. WMLP

49

may not have sufficient available cash each quarter to enable it to pay distributions, which would have a corresponding negative impact on us. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

• the domestic and foreign supply and demand for coal;

• the quantity and quality of coal available from competitors;

• the prices under WMLP’s existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;

• competition for production of electricity from non-coal sources, including the price and availability of alternative fuels;

• domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

• adverse weather, climate or other natural conditions, including natural disasters;

• domestic and foreign taxes;

• domestic and foreign economic conditions, including economic slowdowns;

• legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

• the proximity to, capacity of and cost of transportation and port facilities;

• market price fluctuations for sulfur dioxide emission allowances;

• the level of capital expenditures it makes;

• the cost of acquisitions;

• its debt service requirements and other liabilities;

• fluctuations in its working capital needs;

• its ability to borrow funds and access the capital markets;

• restrictions contained in the debt agreements to which it is a party; and

• the amount of cash reserves established by its general partner.

Any adverse change in these and other factors could result in a decline in WMLP’s ability to have sufficient cash to pay distributions and, in turn, would negatively affect our cash flow.

Our tax position may be adversely affected by virtue of our interest in WMLP.

Our investment in WMLP may adversely affect our tax position.  Whether or not WMLP makes cash distributions to us, we will have income from our interest in WMLP, which may or may not be offset by deductions from WMLP and may or may not be sufficient to fund the taxes on such income.  Further, if WMLP has taxable income, we may be allocated a significant portion of that taxable income.  Additionally, if the Internal Revenue Service ("IRS") successfully contests the positions that WMLP takes, the results of that contest may result in additional taxable income being allocated to us.  We could also be subject to additional taxation by individual states in which we do not conduct business or have assets due to our investment in WMLP.

50

Our acquisition of the general partner of a publicly traded limited partnership may subject us to a greater risk of liability than ordinary business operations.

We own the general partner of WMLP, a publicly traded limited partnership. The general partner of WMLP may be deemed to have undertaken fiduciary obligations with respect to WMLP and its limited partners. Such fiduciary obligations may require a higher standard of conduct than ordinary business operations and, therefore, may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WMLP may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest. Any liability resulting from such claims could be material.

Although we control WMLP through our ownership of the GP, the GP owes fiduciary duties to WMLP’s unitholders, which may conflict with the interests of our shareholders.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and WMLP and its limited partners, on the other hand. The directors and officers of the GP have fiduciary duties to manage WMLP in a manner beneficial to us, as the sole member of the GP. At the same time, the GP has fiduciary duties to manage the limited partnership in a manner beneficial to WMLP and its limited partners. The board of directors of the GP, and in certain cases the conflicts committee of the board, will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest. For example, conflicts of interest with WMLP may arise in the following situations:

• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and WMLP, on the other hand;

• the determination of the amount of cash to be distributed to WMLP’s limited partners and the amount of cash to be reserved for the future conduct of WMLP’s business; and

• the determination whether to make borrowings under WMLP’s revolving credit facility to pay distributions to its limited partners.

In addition, subject to certain conditions, the Term Loan Credit Agreement, the Indenture and the Revolving Credit Facility Agreement permit us to transfer certain assets, including in certain instances equity interests we hold in other entities, to WMLP and its subsidiaries. Provided that we comply with the applicable conditions, we may transfer a significant portion of our assets to WMLP and its subsidiaries, which will not be restricted subsidiaries or guarantors under the Term Loan or the 8.75% Notes or borrowers under the Revolving Credit Facility.

Because we own a controlling interest in WMLP, any internal control deficiencies at WMLP could impact our ability to accurately report our financial results or prevent fraud.

Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. The consummation of the WMLP transactions expanded Westmoreland by adding a significant subsidiary with separate financial reporting. The addition of WMLP’s financial reporting may have adverse effects on our internal control over financial reporting.

The ongoing oversight of the operations of WMLP following the WMLP transactions could create additional risks to our disclosure controls that we may not foresee. WMLP is a separate, publicly traded master limited partnership, or MLP. However, due to our significant equity ownership in WMLP and ownership of the GP, we consolidate the results of WMLP in our public financial statements. To the extent WMLP’s internal control systems are deficient, the integrity of our financial statements and results could be affected and we could fail to meet our regulatory reporting obligations in a timely manner, which ultimately could harm our operating results.

We may not realize the anticipated benefits of recent or future acquisitions, potential synergies, due to challenges associated with integration and other factors.

The long-term success of the acquisitions will depend in part on the success of our management in efficiently integrating the operations, technologies and personnel acquired entities or operations. Our management’s inability to meet the challenges involved in successfully integrating acquired entities or operations or to otherwise realizing the anticipated benefits of such transactions could harm our results of operations.

The challenges involved in integration include:

• integrating the operations, processes, people and technologies;

51

• coordinating and integrating regulatory, benefits, operations and development functions;

• demonstrating to customers acquisition will not result in adverse changes in coal quality, delivery schedules and other relevant deliverables;

• managing and overcoming the unique characteristics of acquired entities or operations, such as the specific mining conditions at each of the acquired mines; retaining the personnel of acquired entities or operations and integrating the business cultures, operations, systems and clients of acquired entities or operations with our own;

• consolidating corporate and administrative infrastructures and eliminating duplicative operations and

• administrative functions; and

• identifying the potential unknown liabilities associated with the Acquisitions.

In addition, overall integration will require substantial attention from our management, particularly in light of the geographically dispersed operations of acquired mines relative to our other mines and operations and the unique characteristics of the acquired assets. If our senior management team is required to devote considerable amounts of time to the integration process, it will decrease the time they will have to manage our business, develop new strategies and grow our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Furthermore, the anticipated benefits and synergies of acquisitions are based on assumptions and current expectations, with limited actual experience, and assume that we will successfully integrate and reallocate resources without unanticipated costs and that our efforts will not have unforeseen or unintended consequences. In addition, our ability to realize the benefits and synergies of the acquisitions could be adversely impacted to the extent that relationships with existing or potential customers, suppliers or the workforce is adversely affected as a consequence of the Acquisitions, as a result of further weakening of global economic conditions, or by practical or legal constraints on our ability to successfully integrate operations.

We cannot assure you that we will successfully or cost-effectively integrate acquired entities or operations into our operations in a timely manner, or at all, and we may not realize the anticipated benefits of the acquisition, including potential synergies or growth opportunities, to the extent or in the time frame anticipated. The failure to do so could have a material adverse effect on our financial condition, results of operations and business.

Our operations outside the United States may subject us to additional risks.

A significant portion of our assets, operations and revenues are located in Canada, and we will be subject to risks inherent in business operations outside of the United States. These risks include, without limitation:

• impact of currency exchange rate fluctuations among the U.S. dollar, the Canadian dollar and foreign currencies relating to our export business, which may reduce the U.S. dollar value of the revenues, profits and cash flows we receive from non-U.S. markets or of our assets in non-U.S. countries or increase our supply costs, as measured in U.S. dollars in those markets;

• exchange controls and other limits on our ability to repatriate earnings from other countries;

• political or economic instability, social or labor unrest or changing macroeconomic conditions or other changes in political, economic or social conditions in the respective jurisdictions;

• different regulatory structures (including creditor rights that may be different than in the United States) and unexpected changes in regulatory environments, including changes resulting in potentially adverse tax consequences or imposition of onerous trade restrictions, price controls, industry controls, safety controls, employee welfare schemes or other government controls;

• increased financial accounting and reporting burdens and complexities resulting from the conversion and integration of the Canadian Subsidiaries’ Canadian dollar denominated, non-GAAP results of operations and statement of financial condition into GAAP-complaint financial statements that can be consolidated with our historical financial reports;

• tax rates that may exceed those in the United States and earnings that may be subject to withholding requirements or that may be subject to tax in the United States prior to repatriation and incremental taxes upon repatriation;

• difficulties and costs associated with complying with, and enforcement of remedies under, a wide variety of complex domestic and international laws, treaties and regulations;

• distribution costs, disruptions in shipping or reduced availability of freight transportation; and

52

• imposition of tariffs, quotas, trade barriers and other trade protection measures, in addition to import or export licensing requirements imposed by various foreign countries.

In addition, our management may be required to devote significant time and resources to adapting our systems, policies and procedures in order to successfully manage the integration and operation of foreign assets.

The Buckingham Acquisition may subject us to increased regulation and risks associated with underground mining.

The operations we acquired in the Buckingham acquisition primarily consist of underground mines. Underground mining operations are generally subject to more stringent safety and health standards than surface mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations. Our re-entry into underground mining operations will subject us to increased regulatory scrutiny and increased costs of regulatory compliance.

ITEM 1B — UNRESOLVED STAFF COMMENTS.

None

ITEM 2 — PROPERTIES.

See “Coal - U.S. Segment - Properties”, “Coal - Canada Segment - Properties”, “Coal - WMLP Segment - Properties”, and “Power Segment” under Item 1 for information relating to our properties and reserves.

ITEM 3 — LEGAL PROCEEDINGS.

We are subject, from time-to-time, to various proceedings, lawsuits, disputes, and claims (“Actions”) arising in the ordinary course of our business. Many of these Actions raise complex factual and legal issues and are subject to uncertainties. We cannot predict with assurance the outcome of Actions brought against us. Accordingly, adverse developments, settlements, or resolutions may occur and may result in a negative impact on income in the quarter of such development, settlement, or resolution. However, we do not believe that the outcome of any current Action would have a material adverse effect on our financial results.

ITEM 4 —MINE SAFETY DISCLOSURE.

On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"). Section 1503(a) of the Dodd-Frank Act contains reporting requirements regarding mine safety. Mine safety violations and other regulatory matters, as required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, are included as Exhibit 95.1 to this report on Form 10-K.

53

PART II

ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our common stock is listed and traded on the NASDAQ Global Market under the symbol WLB.

Holders

As of March 3, 2015, based on inquiry there were 1,069 holders of record of our common stock.

The following table shows the range of sales prices for our common stock for the past two years, as reported by the NASDAQ Global Market.

	Sales Prices Common Stock
	High		Low
2013
First Quarter	$	12.00	$	9.40
Second Quarter	12.30		10.77
Third Quarter	13.79		10.96
Fourth Quarter	19.75		12.91
2014
First Quarter	$	30.00	$	18.31
Second Quarter	37.15		25.79
Third Quarter	45.19		33.60
Fourth Quarter	40.99		27.49

Dividend Policy

Holders of our common stock are entitled to receive such dividends as our Board may declare from time to time from any surplus that we may have. We have not paid dividends on our common stock for some time and we do not anticipate paying any common stock dividends in the near future. In addition, the Indenture, the Term Loan Credit Agreement and the Revolving Credit Facility Agreement restrict our ability to pay dividends on, or make other distributions in respect of, our capital stock unless we are able to meet certain ratio tests or other financial requirements. Should we be permitted to pay dividends pursuant to such instruments, the payment of such dividends will be dependent upon earnings, financial condition and other factors considered relevant by our Board and will be subject to limitations imposed under Delaware law.

Issuer Purchase of Equity Securities

None.

Stock Performance Graph

This performance graph compares the cumulative total stockholder return on our common stock for the five-year period December 31, 2009 through December 31, 2014 with (i) the cumulative total return over the same period of the NASDAQ Index, (ii) the cumulative total return over the same period of the NYSE MKT Composite Index, (iii) our former peer group, which consisted of Alliance Resource Partners, L.P., Cloud Peak Energy, Inc., James River Coal Company, Rhino Resource Partners, L.P. and Patriot Coal Corporation and (iv) our current peer group index, which consists of Arch Coal Inc., Alliance Resource Partners, L.P., Cloud Peak Energy, Inc., Foresight Energy LP, Peabody Energy Corporation, and Rhino Resource Partners, L.P. The graph assumes that:

• You invested $100 in Westmoreland Coal common stock and in each index at the closing price on December 31, 2009;

• All dividends were reinvested;

• Annual reweighting of the peer groups; and

• You continued to hold your investment through December 31, 2014.

You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance. The indices used are included for comparative purposes only and do not indicate

54

an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common stock.

	At December 31,
Company/Market/Peer Group	2009		2010		2011		2012		2013		2014
Westmoreland Coal Company	$	100.00	$	134.01	$	143.10	$	104.83	$	216.50	$	372.73
NYSE MKT Composite Index	$	100.00	$	125.53	$	133.39	$	142.30	$	151.25	$	156.94
NASDAQ Financial Index	$	100.00	$	113.56	$	103.72	$	124.50	$	175.23	$	188.39
2014 Peer Group Index	$	100.00	$	147.57	$	84.86	$	65.55	$	57.00	$	35.67
2013 Peer Group Index	$	100.00	$	142.88	$	114.88	$	83.14	$	99.55	$	94.26

55

ITEM 6 —SELECTED FINANCIAL DATA.

Westmoreland Coal Company and Subsidiaries

Five-Year Review

	2014(2)			2013			2012(3)			2011			2010
Consolidated Statements of Operations Information	(In thousands; except per share data)
Revenues	$	1,115,992		$	674,686		$	600,437		$	501,713		$	506,057
Operating income (loss)	(42,975		)	25,362			28,872			10,626			20,521
Loss from continuing operations(1)	(173,180		)	(8,127		)	(13,662		)	(36,875		)	(3,170		)
Less net loss attributable to noncontrolling interest	(921		)	(3,430		)	(6,436		)	(3,775		)	(2,645		)
Less preferred stock dividend requirements	859			1,360			1,360			1,360			1,360
Net loss applicable to common shareholders	$	(173,118	)	$	(6,057	)	$	(8,586	)	$	(34,460	)	$	(1,885	)
Per common share (basic and diluted):
Loss from continuing operations	$	(10.86	)	$	(0.56	)	$	(0.97	)	$	(2.80	)	$	(0.29	)
Net loss applicable to common shareholders	$	(10.86	)	$	(0.42	)	$	(0.61	)	$	(2.61	)	$	(0.17	)
Consolidated Balance Sheet Information (end of period)
Working capital deficit	$	(13,126	)	$	(7,989	)	$	(11,600	)	$	(21,669	)	$	(35,793	)
Net property, plant and equipment	927,662			490,036			512,840			396,732			416,955
Total assets	1,829,578			946,685			936,115			759,172			750,306
Total debt	984,787			339,837			360,989			282,269			242,104
Shareholders’ deficit	(349,445		)	(187,879		)	(286,231		)	(249,858		)	(162,355		)
Other Consolidated Data:
Net cash provided by (used in):
Operating activities	$	50,353		$	80,717		$	57,144		$	44,735		$	45,353
Investing activities	(432,772		)	(21,897		)	(123,534		)	(33,639		)	(29,180		)
Financing activities	338,706			(29,320		)	67,217			13,912			(20,917		)
Capital expenditures	50,326			28,591			21,032			27,594			22,814
Adjusted EBITDA(4)	175,351			116,265			105,432			73,116			81,616
Tons sold	44,849			24,927			21,745			21,816			25,152

____________________ 

(1) Includes a loss on extinguishment of debt of $49.2 million, $0.1 million, $2.0 million and $17.0 million in 2014, 2013, 2012 and 2011, respectively. Includes a derivative loss of $31.1 million in 2014. Includes restructuring charges of $15.0 million and $5.1 million in 2014 and 2013, respectively. Includes a non-cash tax benefit of $4.9 million in 2013.

(2) On April 28, 2014, we acquired the Canadian Subsidiaries. Our results of operations include the Canadian Subsidiaries’ results of operations from the date of acquisition. On December 31, 2014, we acquired Westmoreland Resources GP, LLC; therefore, balance sheet information and cash flow information includes the effect of this acquisition.

(3) On January 31, 2012, we acquired the Kemmerer Mine. Our results of operations include Kemmerer’s results of operations from the date of acquisition. Kemmerer’s results are reflected in our Coal - U.S. segment. We acquired additional debt to finance the acquisition of the Kemmerer Mine.

(4) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Selected Financial Data” section.

We did not declare cash dividends on common shares for the five years ended December 31, 2014. The financial data presented above should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operation in Part II, Item 7 of this report, which includes a discussion of factors that materially affect the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.

Reconciliation of Adjusted EBITDA to Net Loss

EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating

56

performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

• are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

• help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:

• do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;

• do not reflect income tax expenses or the cash requirements necessary to pay income taxes;

• do not reflect changes in, or cash requirements for, our working capital needs; and

• do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.

In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.

The tables below show how we calculated Adjusted EBITDA, including a breakdown by segment, and reconciles Adjusted EBITDA to net loss, the most directly comparable GAAP financial measure.

57

	For the Years Ended December 31,
	2014			2013			2012			2011			2010
	(In thousands)
Reconciliation of Adjusted EBITDA to Net loss
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)	$	(36,875	)	$	(3,170	)
Income tax (benefit) expense from continuing operations	232			(4,782		)	90			(426		)	(141		)
Interest income	(6,400		)	(1,366		)	(1,496		)	(1,444		)	(1,747		)
Interest expense	84,234			39,937			42,677			29,769			22,992
Depreciation, depletion and amortization	100,778			67,231			57,145			45,594			44,690
Accretion of ARO and receivable	21,604			12,681			12,189			10,878			11,540
Amortization of intangible assets and liabilities	138			665			658			657			590
EBITDA	27,406			106,239			97,601			48,153			74,754
Restructuring charges	14,989			5,078			—			—			—
Loss on foreign exchange	4,016			—			—			—			—
Loss on extinguishment of debt	49,154			64			1,986			17,030			—
Acquisition related costs (1)	26,785			—			—			—			—
Customer payments received under loan and lease receivables(2)	12,388			—			—			—			—
Derivative loss	31,100			—			—			—			—
Loss (gain) on sale of assets and other adjustments	3,431			(438		)	(195		)	3,212			2,813
Share-based compensation	6,082			5,322			6,040			4,721			4,049
Adjusted EBITDA	$	175,351		$	116,265		$	105,432		$	73,116		$	81,616

__________________

(1) Includes acquisition and transition costs included in Selling and administrative on the Consolidated Statements of Operations and the impact of cost of sales related to the sale of inventory written up to fair value in the Canadian Acquisition.

(2) Represents a return of and on capital. These amounts are not included in operating income or operating cash flows, as the capital outlays are treated as loan and lease receivables, but are included within Adjusted EBITDA so that the cash received by the Company is treated consistently with all other contracts within the Company that do not result in loan and lease receivable accounting.

58

ITEM 7 —MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis contains forward-looking statements and estimates that involve risks and uncertainties. Actual results could differ materially from these estimates. Factors that could cause or contribute to differences from estimates include those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” contained in Item 1 above.

Overview

Westmoreland Coal Company is an energy company employing approximately 3,440 employees. We conduct our operations through our subsidiaries and the principal sources of cash flow to us are distributions from our operating subsidiaries. Our operations include 13 wholly-owned coal mines in the U.S. and Canada, a char production facility, a 50% stake in an activated carbon plant, and two coal-fired power generation units. We also own the general partner of and 79% of the total equity interest in WMLP.

We classify our business into six segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage and Corporate. Our principal operating segments are our Coal - U.S., Coal - Canada, Coal - WMLP and Power segments. Our two non-operating segments are our heritage and corporate segments. Our heritage segment primarily includes the costs of benefits we provide to former mining operation employees and our corporate segment consists primarily of corporate administrative expenses.

One of the major factors affecting the volume of coal that we sell in any given year is the demand for coal-generated electric power, as well as the specific demand for coal by our customers. Numerous factors affect the demand for electric power and the specific demands of customers including weather patterns, the presence of hydro or wind in our particular energy grids, environmental and legal challenges, political influences, energy policies, international and domestic economic conditions, power plant outages and other factors discussed herein.

We sell almost all of our coal and electricity production under long-term agreements. Our long-term coal contracts typically contain either full pass-through of our costs or price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised in line with broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs. We refer to these contracts as “cost protected” contracts.

For our contracts that are not cost protected in nature, we have exposure to inflation and price risk for supplies used in the normal course of production such as diesel fuel and explosives. In line with the worldwide mining industry, we have experienced increased operating costs for mining equipment, diesel fuel and other supplies, such as tires. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time-to-time.

Please see Item 1 - Business, under “Overview,” “2014 Transactions,” “Recent Developments” and “Power Segment” for information regarding the following transactions that occurred during 2014:

• Canadian Acquisition

• Equity Offering

• Sale of Port Access

• Debt Restructuring (including the tender offer, 8.75% Notes offering, Term Loan and Revolving Credit Facility)

• WMLP Transactions

• Buckingham Acquisition

• ROVA Agreement

59

Results of Operations

Items that Affect Comparability of Our Results

For 2014 and each of the prior two years, our results have included items that do not relate directly to ongoing operations. The income (expense) components of these items were as follows:

Year Ended December 31,	2014			2013			2012
	(In thousands)
Loss on extinguishment of debt	$	(49,154	)	$	(64	)	$	(1,986	)
Derivative loss	(31,100		)	—			—
Acquisition and transition costs	(26,785		)	—			—
Restructuring charges	(14,989		)	(5,078		)	—
Incremental interest incurred before close of transaction	(11,191		)	—			—
Canadian Acquisition bridge facility commitment fee	(4,875		)	—			—
Foreign exchange loss	(4,016		)	—			—
Impact (pre-tax)	$	(142,110	)	$	(5,142	)	$	(1,986	)
Tax effect of other comprehensive income gains	$	—		$	4,892		$	—

Items recorded in 2014

• We recorded $49.2 million of loss on extinguishment of debt related to the payoff of the 10.75% Notes, the WML term debt, and the WMLP debt. This loss included $44.5 million of make-whole payments with the remaining loss due to the write-off of unamortized debt issuance costs, debt discounts, and debt premiums.

• We recorded $31.1 million of derivative losses related to ROVA's purchased-power contracts.

• We recorded $26.8 million of acquisition and transition costs as a result of our WMLP and Canadian Acquisitions, which includes the impact on cost of sales related to the sale of inventory written up to fair value in the acquisition.

• We recorded $15.0 million of restructuring charges related to a restructuring plan in order to reduce our overall cost structure. Most of the restructuring charges related to our Canadian and WMLP operations and included termination benefits and outplacement costs.

• We recorded $11.2 million of incremental interest expense related to the $425 million of additional 10.75% Notes issued in connection with the Canadian Acquisition. This incremental interest represents interest expense from the February 7, 2014 closing date of the 10.75% Notes to the April 28, 2014 closing date of the Canadian Acquisition.

• We recorded $4.9 million of interest expense related to the Canadian Acquisition bridge facility. Upon closing of the $425 million private offering of 10.75% Notes, our bridge facility commitment expired unexercised and as a result, the related commitment fee of $4.9 million was expensed and is included in Interest expense.

• We recorded a $4.0 million loss on foreign exchange. The majority of this loss relates to two foreign currency exchange forward contracts to purchase Canadian dollars in order to hedge a portion of our exposure to fluctuating rates of exchange on Canadian dollar-denominated Canadian Acquisition cash flows.

Items recorded in 2013

• We recorded $0.1 million of loss on extinguishment of debt related to repurchases of 10.75% Notes with a principal amount of $0.5 million. The loss on the repurchases was measured based on the carrying value of the repurchased portion of the 10.75% Notes, which included a portion of the unamortized debt issue costs and the debt discount on the dates of repurchase.

• We recorded $5.1 million of restructuring charges related to the ROVA restructuring.

• We recorded an income tax benefit of $4.9 million related to a tax effect of other comprehensive income gains, primarily related to decreases in our pension and postretirement medical obligations.

60

Items recorded in 2012

• We recorded $2.0 million of loss on extinguishment of debt related to repurchases of 10.75% Notes with a principal amount of $23.0 million. The loss on the repurchases was measured based on the carrying value of the repurchased portion of the 10.75% Notes, which included a portion of the unamortized debt issue costs and the debt discount on the dates of repurchase.

2014 Compared to 2013

Summary

The following table shows the comparative consolidated results and changes between periods:

	Year Ended December 31,
							Increase / (Decrease)
	2014			2013			$		%
	(In millions)
Revenues	$	1,116.0		$	674.7		$	441.3	65.4	%
Net loss applicable to common shareholders	(173.1		)	(6.1		)	167.0		2,737.7	%
Adjusted EBITDA(1)	175.4			116.3			59.1		50.8	%

____________________

(1) Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our revenues for 2014 increased primarily due to the Canadian Acquisition, new customer sales, and fewer customer outages.

Our net loss applicable to common shareholders for 2014 increased by $25.2 million, excluding $142.1 million of expense during 2014 and $0.2 million of expense during 2013 discussed in Items that Affect Comparability of Our Results. The primary factors, in aggregate, driving this increase in net loss were:

	2014
	(In millions)
Increase in interest expense due to increased debt levels	$	(21.9	)
Decrease in our power segment operating income due to the renegotiated ROVA contract, unfavorable power prices and lower demand	(13.4		)
Decrease in our Coal - U.S. segment primarily due to weather impacts as well as rail service issues at our Absaloka Mine	(10.1		)
Increase in our Coal - Canada segment due to the Canadian Acquisition	19.3
Increase due to other factors	0.9
Total	$	(25.2	)

Coal - U.S. Segment Operating Results

The following table shows comparative coal revenues, operating income and sales volume, and percentage changes between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2014		2013		$			%
	(In thousands, expect per ton data)
Revenues	$	642,075	$	587,119	$	54,956		9.4	%
Operating income	24,183		44,471		(20,288		)	(45.6	)%
Adjusted EBITDA(1)	111,699		116,604		(4,905		)	(4.2	)%
Tons sold—millions of equivalent tons	28.3		24.9		3.4			13.7	%

____________________

(1) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our 2014 U.S. coal segment revenues and tons sold increased primarily due to new customer sales at our Absaloka Mine and fewer customer outages affecting our Absaloka and Beulah Mines. Operating income was negatively impacted by

61

weather impacts, rail service issues at our Absaloka Mine, acquisition costs, and increased maintenance expenses. These decreases in operating income were partially offset with increased revenues described above.

Coal - Canada Segment Operating Results

The following table shows comparative coal revenues, operating income and sales volume between periods:

	Year Ended December 31,
	2014			2013
	(In thousands, expect per ton data)
Revenues	$	388,664		$	—
Operating income	(2,670		)	—
Adjusted EBITDA(1)	79,010			—
Tons sold—millions of equivalent tons	16.6			—

____________________

(1) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

The above table represents results from the Canadian Acquisition date of April 28, 2014 to December 31, 2014. Operating income was negatively impacted by $14.2 million of cost of sales related to the sale of inventory written up to fair value in the acquisition and $9.6 million of restructuring charges.

Coal - WMLP Segment Operating Results

The 2014 WMLP coal segment operating loss was $2.8 million due to expenses related to severance charges that occurred on December 31, 2014. These operations were acquired on December 31, 2014, therefore, information for the year ended December 31, 2014 includes minimal operating activity.

Power Segment Operating Results

The following table shows comparative power revenues, operating income and production and percentage changes between periods:

	Year Ended December 31,
						Increase / (Decrease)
	2014			2013		$			%
	(In thousands)
Revenues	$	85,253		$	87,567	$	(2,314	)	(2.6	)%
Operating income	(35,023		)	4,907		(39,930		)	(813.7	)%
Adjusted EBITDA(1)	6,718			20,886		(14,168		)	(67.8	)%

____________________ 

(1) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our 2014 power segment revenues decreased and operating income decreased to a loss due to the renegotiated ROVA contract, unfavorable power prices and cooler than average weather during the summer. Operating income was also negatively impacted by $31.1 million of derivative losses on ROVA's purchased-power contracts.

Heritage Segment Operating Results

The following table shows comparative heritage segment’s operating expenses and percentage change between periods: 

	Year Ended December 31,
					Increase / (Decrease)
	2014		2013		$		%
	(In thousands)
Heritage segment operating expenses	$	14,858	$	14,498	$	360	2.5	%

Our 2014 heritage segment operating expenses were comparable to 2013.

62

Corporate Segment Operating Results

The following table shows comparative corporate segment’s operating expenses and percentage change between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2014		2013		$		%
	(In thousands)
Corporate segment operating expenses	$	11,824	$	9,518	$	2,306	24.2	%

Our 2014 corporate segment operating expenses increased due to higher compensation expenses.

Nonoperating Results (including interest expense, interest income, other income, income tax expense (benefit), and net loss attributable to noncontrolling interest)

Our interest expense for 2014 increased to $84.2 million compared with $39.9 million for 2013 primarily due to higher debt levels.

Our interest income for 2014 increased to $6.4 million compared with $1.4 million for 2013 due to the Canadian Acquisition.

Our other income for 2014 was comparable to 2013.

Our income tax expense for 2014 was comparable to 2013, excluding $4.9 million of income discussed in Items that Affect Comparability of Our Results.

Our net loss attributable to noncontrolling interest for 2014 decreased to $0.9 million compared with $3.4 million for 2013 related to the elimination of the noncontrolling interest effective January 1, 2014 offset with the start of noncontrolling interest effective December 31, 2014 regarding the WMLP Acquisition.

2013 Compared to 2012

Summary

The following table shows the comparative consolidated results and changes between periods:

	Year Ended December 31,
							Increase / (Decrease)
	2013			2012			$		%
	(In millions)
Revenues	$	674.7		$	600.4		$	74.3	12.4	%
Net loss applicable to common shareholders	(6.1		)	(8.6		)	2.5		29.1	%
Adjusted EBITDA(1)	116.3			105.4			10.9		10.3	%

____________________ 

(1) Adjusted EBITDA , a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our revenues for 2013 increased primarily due to stronger power demand, favorable weather conditions and one additional month of Kemmerer operations. A new customer and Unit 3 resuming operations at our Absaloka Mine also contributed to increased revenues. In addition, our ROVA power plant experienced improved performance and fewer unplanned outages.

Our net loss applicable to common shareholders for 2013 decreased by $0.8 million, excluding $0.2 million of expense during 2013 and $2.0 million of expense during 2012 discussed in Items that Affect Comparability of Our Results. The primary factors, in aggregate, driving this decrease in net loss were:

63

	2013
	(In millions)
Decrease in interest expense due to lower debt levels.	$	2.7
Decrease in our corporate segment operating expenses due primarily to improved performance at our captive insurance entity and one-time recruiting and compensation expenses.	1.9
Increase in our power segment operating income due improved performance and fewer unplanned outages.	1.7
Decrease in our coal segment primarily due to costs incurred to increase production levels at the Absaloka Mine, higher royalty coal mined at the Kemmerer Mine, a contract adjustment related to employee benefit costs, depreciation adjustments and acquisition costs.	(5.3		)
Decrease due to other factors.	(0.2		)
Total	$	0.8

Coal - U.S. Segment Operating Results

The following table shows comparative coal revenues, operating income and sales volume, and percentage changes between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2013		2012		$			%
	(In thousands, expect per ton data)
Revenues	$	587,119	$	519,152	$	67,967		13.1	%
Operating income	44,471		48,235		(3,764		)	(7.8	)%
Adjusted EBITDA(1)	116,604		110,835		5,769			5.2	%
Tons sold—millions of equivalent tons	24.9		21.7		3.2			14.7	%

____________________ 

(1) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our 2013 U.S. coal segment revenues increased primarily due to stronger power demand, favorable weather conditions and one additional month of Kemmerer operations. A new customer and Unit 3 resuming operations at our Absaloka Mine also contributed to increased revenues. These positive factors allowed us to overcome the impact of two significant unplanned customer outages which occurred during 2013. Operating income decreased due to higher costs at the Absaloka Mine in preparation for new contracts and higher production levels, higher royalty coal mined at the Kemmerer Mine, a contract adjustment related to employee benefit costs, depreciation adjustments, and acquisition costs. These decreases in operating income were partially offset with increased revenues described above.

Power Segment Operating Results

The following table shows comparative power revenues, operating income and production and percentage changes between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2013		2012		$			%
	(In thousands)
Revenues	$	87,567	$	81,285	$	6,282		7.7	%
Operating income	4,907		8,244		(3,337		)	(40.5	)%
Adjusted EBITDA(1)	20,886		19,054		1,832			9.6	%

____________________ 

(1) Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Our 2013 power segment revenues, operating income (excluding $5.1 million of expenses discussed in Items that Affect Comparability of Our Results) and megawatt hours increased due to improved performance and fewer unplanned outages at our ROVA power plant.

64

Heritage Segment Operating Results

The following table shows comparative heritage segment’s operating expenses and percentage change between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2013		2012		$			%
	(In thousands)
Heritage segment operating expenses	$	14,498	$	14,711	$	(213	)	(1.4	)%

Our 2013 heritage segment operating expenses were comparable to 2012.

Corporate Segment Operating Results

The following table shows comparative corporate segment’s operating expenses and percentage change between periods:

	Year Ended December 31,
					Increase / (Decrease)
	2013		2012		$			%
	(In thousands)
Corporate segment operating expenses	$	9,518	$	12,896	$	(3,378	)	(26.2	)%

Our 2013 corporate segment operating expenses decreased primarily due to a 2012 deductible on a claim paid by our captive insurance entity related to the business interruption claim at our Absaloka Mine, however this expense was offset by proceeds recorded in the coal segment and thus had no impact on a consolidated basis. In addition, expenses decreased due to improved performance at our captive insurance entity and one-time recruiting and compensation expenses.

Nonoperating Results (including interest expense, interest income, other income (loss), income tax expense (benefit), and net loss attributable to noncontrolling interest)

Our interest expense for 2013 decreased to $39.9 million compared with $42.7 million for 2012 primarily due to lower overall debt levels.

Our interest income and other income for 2013 was comparable to 2012.

Our income tax benefit for 2013 was comparable to 2012, excluding $4.9 million of income discussed in Items that Affect Comparability of Our Results.

Our loss attributable to noncontrolling interest for 2013 decreased to $3.4 million compared with $6.4 million for 2012 related to decreased losses from a partially owned consolidated subsidiary.

Reconciliation of Adjusted EBITDA to Net Loss

The discussion in “Results of Operations” in 2014, 2013 and 2012 includes references to our Adjusted EBITDA results. EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

• are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

• help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:

65

• do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;

• do not reflect income tax expenses or the cash requirements necessary to pay income taxes;

• do not reflect changes in, or cash requirements for, our working capital needs; and

• do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.

In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.

The tables below show how we calculated Adjusted EBITDA, including a breakdown by segment, and reconciles Adjusted EBITDA to net loss and from Adjusted EBITDA to net cash provided by operating activities, the most directly comparable GAAP financial measures.

	For the Years Ended December 31,
	2014			2013			2012
	(In thousands)
Reconciliation of Adjusted EBITDA to Net loss
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)
Income tax (benefit) expense from continuing operations	232			(4,782		)	90
Interest income	(6,400		)	(1,366		)	(1,496		)
Interest expense	84,234			39,937			42,677
Depreciation, depletion and amortization	100,778			67,231			57,145
Accretion of ARO and receivable	21,604			12,681			12,189
Amortization of intangible assets and liabilities	138			665			658
EBITDA	27,406			106,239			97,601
Restructuring charges	14,989			5,078			—
Loss on foreign exchange	4,016			—			—
Loss on extinguishment of debt	49,154			64			1,986
Acquisition related costs (1)	26,785			—			—
Customer payments received under loan and lease receivables (2)	12,388			—			—
Derivative loss	31,100			—			—
Loss (gain) on sale of assets and other adjustments	3,431			(438		)	(195		)
Share-based compensation	6,082			5,322			6,040
Adjusted EBITDA	$	175,351		$	116,265		$	105,432

____________________

(1) Includes acquisition and transition costs included in Selling and administrative on the Consolidated Statements of Operations and the impact of cost of sales related to the sale of inventory written up to fair value in the Canadian Acquisition.

(2) Represents a return of and on capital.  These amounts are not included in operating income or operating cash flows, as the capital outlays are treated as loan and lease receivables, but are included within Adjusted EBITDA so that the cash received by the Company is treated consistently with all other contracts within the Company that do not result in loan and lease receivable accounting.

66

	For the Years Ended December 31,
	2014			2013			2012
	(In thousands)
Adjusted EBITDA by Segment
Coal - U.S.	$	111,699		$	116,604		$	110,835
Coal - Canada	79,010			—			—
Power	6,718			20,886			19,054
Heritage	(14,780		)	(14,498		)	(14,711		)
Corporate	(7,296		)	(6,727		)	(9,746		)
Total	$	175,351		$	116,265		$	105,432

Significant Anticipated Variances between 2014 and 2015 and Related Uncertainties

We expect a number of factors to result in differences in our base business in our results of operation, financial condition and liquidity in 2015 relative to 2014, including the following:

• We expect increased coal ton deliveries primarily due to an additional four months of our Canadian Operations. This is anticipated to result in increased revenues and operating cash flows;

• We expect to make capital investments during 2014 in the range of $74.0 million to $92.0 million, which includes $7.5 million of capital expenditures in Canada related to the expansion of the activated carbon facility;

• We expect our pension and postretirement medical expenses to increase as a result of decreases in discount rates and changes to mortality rates;

• We expect our pension contributions to decrease due to pension funding relief; and

• We expect our reclamation expenditures to increase.

Due to the closing of the WMLP and Buckingham transactions, we expect higher revenues and costs, capital investments and financing costs to produce positive net cash flows.

Liquidity and Capital Resources

We had the following liquidity at December 31, 2014 and 2013:

	December 31,
	2014		2013
	(In millions)
Cash and cash equivalents	$	14.3	$	61.1
WML revolving line of credit	—		23.1
Revolving Credit Facility	16.9		20.0
Total	$	31.2	$	104.2

We anticipate that the $75.0 million increase to the Term Loan that closed on January 22, 2015, availability under our Revolving Credit Facility, our cash from operations, cash on hand and available borrowing capacity will be sufficient to meet our investing, financing, and working capital requirements for the foreseeable future.

We conduct our operations through subsidiaries. Our parent company has significant cash requirements to fund our debt obligations, ongoing heritage health benefit costs, pension contributions, and corporate overhead expenses. The principal sources of cash flow to the parent company are distributions from our principal operating subsidiaries. The cash at all of our subsidiaries is immediately available, except WRMI and WMLP. The cash at our captive insurance entity, WRMI, is available to us through dividends and is subject to maintaining a statutory minimum level of capital, which is two hundred and fifty thousand dollars. The cash at WMLP is available to us through quarterly distributions. WMLP intends to resume quarterly distributions of $0.20 per unit beginning in April 2015, or $4.6 million annually. Based on our current ownership of WMLP, we would expect to receive approximately 79% of WMLP’s distributions. In addition as WMLP's general partner, we are entitled to incentive distribution rights.

67

Under the Term Loan Credit Agreement, we are required to offer a portion of our Excess Cash Flow (as defined by the Agreement) for each fiscal year, beginning with the fiscal year ending December 31, 2015.

Under the Revolving Credit Facility, the maximum available borrowing amount is $50.0 million, and we had $9.6 million of borrowings with outstanding letters of credit in the amount of $23.5 million as of December 31, 2014.

Debt Obligations

8.75% Notes Offering

On December 16, 2014, we completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are our senior secured indebtedness, rank equally in right of payment with all of our existing and future senior indebtedness, including the Term Loan, and rank senior to all of our existing and future indebtedness that is expressly subordinated to the 8.75% Notes. Proceeds from the 8.75% Notes offering and borrowing on the Term Loan were used to repay the outstanding 10.75% Notes with a principal balance of $675.5 million.

We may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the Indenture, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the Indenture. In addition, at any time prior to January 1, 2018, we may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount of the 8.75% Notes to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc., Westmoreland Coal Sales Company Inc. and WCC Land Holding Company Inc. and, to the extent applicable, their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by the GP or WMLP, referred to as the Non-guarantors.

The 8.75% Notes and the guarantees are secured equally and ratably with the Term Loan (i) by first priority liens on substantially all of our and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the Revolving Credit Facility Agreement, a second priority lien on substantially all cash, accounts receivable and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts receivable and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the Term Loan Credit Agreement, who hold identical first and second priority liens, as applicable, on the Notes Collateral.

The Indenture restricts our and our restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to us or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.

The Indenture contains, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2014, we were in compliance with all covenants for these Notes.

Restricted Group and Unrestricted Group Results

Under the Indenture, the Term Loan Credit Agreement and the Revolving Credit Facility Agreement; the GP, WMLP and all of WMLP’s subsidiaries (including WKFCH) were automatically designated as “unrestricted subsidiaries” (the “Unrestricted Group”) following the closing of the WMLP Transactions. All of our other subsidiaries are restricted subsidiaries (the “Restricted Group). Only the Restricted Group provides credit support for our obligations under the 8.75% Notes, the Term Loan and the Revolving Credit Facility. The Unrestricted Group is not subject to any of the restrictive covenants in the Indenture, the Term Loan Credit Agreement or the Revolving Credit Facility Agreement. Conversely, the Restricted Group are not obligors of the $175.0 million WMLP Financing Agreement and such indebtedness is non-recourse to the Restricted Group and its assets.

68

The Indenture requires summary information for the Restricted Group and Unrestricted Group which is provided as follows:

	Restricted Group			Unrestricted Group			Total
	(In thousands)
Balance sheet information as of December 31, 2014:
Cash and cash equivalents	$	8,069		$	6,189		$	14,258
Total current assets	$	316,544		$	44,227		$	360,771
Total assets	$	1,521,826		$	307,752		$	1,829,578
Total current liabilities	$	340,238		$	33,659		$	373,897
Total debt	$	809,752		$	175,035		$	984,787
Total liabilities	$	1,944,292		$	234,731		$	2,179,023
Statement of operations information for the year ended December 31, 2014
Revenues	$	1,115,992		$	—		$	1,115,992
Operating costs and expenses	1,156,184			2,783			1,158,967
Operating loss	(40,192		)	(2,783		)	(42,975		)
Other income and expenses	(128,351		)	(1,622		)	(129,973		)
Loss before income taxes	(168,543		)	(4,405		)	(172,948		)
Income tax expense	232			—			232
Net loss	(168,775		)	(4,405		)	(173,180		)
Less net loss attributable to noncontrolling interest	—			(921		)	(921		)
Net loss attributable to the Parent company	$	(168,775	)	$	(3,484	)	$	(172,259	)

For the year ended December 31, 2014, the Adjusted EBITDA for the Restricted Group was the same as the Company's consolidated Adjusted EBITDA. There was no Adjusted EBITDA associated with the Unrestricted Group since the WMLP Transactions closed on December 31, 2014.

Non-guarantor Restricted Subsidiaries Results

The Indenture requires summary information for non-guarantor subsidiaries (as defined in the Indenture) which is provided as follows:

Absaloka Coal, LLC, Westmoreland Canada LLC, Westmoreland Risk Management, Inc. (“WRMI”), the Canadian Subsidiaries and our Netherlands subsidiary (collectively, the “non-guarantor Restricted Subsidiaries”) had $935.1 million in total assets as of December 31, 2014, representing approximately 51.1% of our consolidated total assets, and generated $388.7 million in revenue for the year ended December 31, 2014 representing approximately 34.8% of our consolidated revenue and generated Adjusted EBITDA of $79.7 million representing approximately 45.4% of our consolidated Adjusted EBITDA. As of December 31, 2014, our non-guarantor Restricted Subsidiaries had $94.5 million of total indebtedness and $557.3 million of total liabilities, and our non-guarantor Canadian Subsidiaries had availability of up to $20.0 million under the Canadian tranche of the Revolving Credit Facility.

Term Loan Credit Agreement

Effective as of December 16, 2014, we entered into the Term Loan Credit Agreement which provided for an initial $350.0 million Term Loan. The Term Loan was issued at a 2.5% discount and matures on December 16, 2020. We may elect to have borrowings under the Term Loan bear interest at a per annum rate of (i) one, two-, three- or six-month LIBOR plus 6.50% or (ii) a base rate (determined with reference to the highest of the prime rate, the Federal Funds Rate plus 0.05%, and one-month LIBOR plus 1.00%) plus 5.50%. The interest rate at December 31, 2014 was 7.50%. With the addition of the Add-on described below, the quarterly principal payment due commencing March 31, 2015 is $1.1 million.

The Term Loan Credit Agreement contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the related Guaranty and Collateral Agreement, the obligations under the Term

69

Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2014, we were was in compliance with all covenants for the Term Loan.

The Term Loan is guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc., Westmoreland Coal Sales Company, Inc. and WCC Land Holding Company, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada LLC or any of its subsidiaries and certain other immaterial subsidiaries).

Term Loan Add-on

On January 22, 2015, we amended the Term Loan Credit Agreement to increase the borrowings under the Term Loan by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the Term Loan Credit Agreement were made in connection with the acquisition of Buckingham. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.

Revolving Credit Facility

During the first quarter of 2014, we amended our existing Revolving Credit Facility Agreement to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, we further amended the Revolving Credit Facility Agreement, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available to our U.S. borrowers and $20.0 million sub-facility available to our Canadian borrowers. The maximum principal amount available for borrowings under the credit agreement can be increased to $100.0 million under certain circumstances. The facility may support an equal amount of letters of credit, which would reduce the balance available under the facility. At December 31, 2014, availability on the Revolving Credit Facility was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit. All extensions of credit under the facility are secured by a first priority security interest in and lien on our cash, inventory and accounts receivable, certain other assets and proceeds thereof. The Revolving Credit Facility has a maturity date of December 31, 2018. We capitalized debt issuance costs of $0.7 million in 2014 related to the Revolving Credit Facility amendments.

Our borrowing base under the Revolving Credit Facility Agreement is determined by reference to our eligible inventory and accounts receivable, and is reduced by the outstanding amount of standby and commercial letters of credit. Borrowings under the Revolving Credit Facility Agreement initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Revolving Credit Facility Agreement) or at a rate 2.75% per annum in excess of LIBOR, at our election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.

The loan agreement contains various affirmative, negative and financial covenants. The financial covenant in the agreement includes a fixed charge coverage ratio. The fixed charge coverage ratio must meet or exceed a specified minimum. We met these covenant requirements as of December 31, 2014.

10.75% Notes

On February 7, 2014, we closed on a private offering of $425.0 million in aggregate principal amount of the 10.75% Notes due 2018 at a price of 106.875% plus accrued interest from February 1, 2014. The private offering had the same terms as the then existing $251.5 million outstanding 10.75% Notes. Total proceeds of the offering were $454.2 million, which included $29.2 million of debt premium. The net proceeds of the offering of the $425.0 million private offering were used to finance the $282.8 million initial cash payment for the Canadian Acquisition and cash transaction costs associated with the Canadian Acquisition and the private offering of approximately $24.0 million. The remaining balance of the proceeds were used to fund the prepayment of the WML debt and for other general corporate purposes. We recorded $12.5 million of loss on extinguishment of debt for the year ended December 31, 2014 related to the payoff of the WML term debt. This loss included an $11.6 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs. In connection with the WML prepayment, the WML revolving credit facility was terminated.

On December 16, 2014, we used the proceeds from the 8.75% Notes and the Term Loan to pay the $675.5 million aggregate outstanding balance of the 10.75% Notes. In connection with the repayment of the 10.75% Notes, we recorded loss on extinguishment of $34.9 million for the year ended December 31, 2014. This loss included an $32.9 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs and unamortized debt premium.

WMLP Term Loan Facility

On December 31, 2014, WMLP closed its WMLP Loan. The WMLP Loan consists of an initial $175.0 million term loan, with an option for additional term loans up to $120.0 million for certain permitted acquisitions. The WMLP Loan matures in December 2018. The WMLP Financing Agreement contains customary financial and other covenants. Borrowings under the WMLP Loan are secured by substantially all of the assets of Oxford, WMLP and their subsidiaries. Proceeds of the WMLP

70

Loan were used to retire WMLP’s then existing first and second lien credit facilities and to pay fees and expenses related to the new WMLP Loan, with the limited amount of remaining proceeds being available as working capital.

As of December 31, 2014, the $175.0 million outstanding under the WMLP Loan bears interest at a variable rate per annum equal to, at the WMLP’s option, LIBOR (as defined in the WMLP Financing Agreement, but with a floor of 0.75% plus 8.50% or the Reference Rate (as defined in the WMLP Financing Agreement) plus 9.5%. As of December 31, 2014, the WMLP Loan had a cash interest rate of 9.25%, consisting of the LIBOR floor of 0.75% plus 8.50%.

The WMLP Loan facility also provides for “PIK Interest” (paid-in-kind interest as defined in the WMLP Financing Agreement) at a variable rate per annum between 1.00% and 3.00% based on whether WMLP’s consolidated total net leverage ratio (as defined in the WMLP Financing Agreement is greater than a certain level. The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest, if any, added quarterly to the then outstanding principal amount of the WMLP Loan. PIK Interest under the WMLP Loan was inconsequential for the year ended December 31, 2014.

As a result of WMLP refinancing its previous credit facilities, we recorded a $1.6 million loss on extinguishment of debt in the year ended December 31, 2014 as it pertains to cost associated with repayment of the existing outstanding debt owing by WMLP.

As of December 31, 2014, WMLP was in compliance with all covenants under the terms of the WMLP term loan.

Capital Leases

During the year ended December 31, 2014, we entered into $15.6 million of new capital leases. In addition, we assumed $122.6 million of capital lease obligations in the Canadian Acquisition.

Heritage Health Costs and Pension Contributions

Our liquidity continues to be affected by our heritage health and pension obligations as follows:

	2015 Expected		2014 Actual		2013 Actual		2012 Actual
	(In millions)
Postretirement medical benefits	$	12.2	$	11.8	$	12.0	$	12.0
CBF premiums	2.0		2.0		2.2		2.3
Workers’ compensation benefits	0.4		0.4		0.6		0.5
Total heritage health payments	14.6		14.2		14.8		14.8
Pension contributions (1)	1.2		4.1		0.6		0.2

____________________ 

(1) Of the 2014 pension contributions we made $1.9 million through the contribution of Company stock.

Historical Sources and Uses of Cash

The following is a summary of cash provided by or used in each of the indicated types of activities:

	Years Ended December 31,
	2014			2013
	(In thousands)
Cash provided by (used in):
Operating activities	$	50,353		$	80,717
Investing activities	(432,772		)	(21,897		)
Financing activities	338,706			(29,320		)

Cash provided by operating activities decreased$30.4 million in 2014 compared to 2013, primarily due to incremental interest from higher debt levels, acquisition costs, unfavorable impacts of weather, the renegotiated ROVA contract and unfavorable power prices, and the expiration of the ICTC.

Cash used in investing activities increased $410.9 million in 2014 compared to 2013 primarily due to the $322.6 million cash consideration for the Canadian Acquisition, which includes $39.8 million for a working capital adjustment. In addition, $30.0 million was paid in connection with the WMLP transactions. Capital expenditures were $50.3 million and $28.6 million for 2014 and 2013, respectively.

71

Cash provided by financing activities increased$368.0 million for 2014 compared to 2013, primarily due to the Canadian Acquisition debt and the July 16, 2014 equity offering. Debt repayments were $955.2 million and $28.1 million for 2014 and 2013, respectively.

Our working capital deficit at December 31, 2014 increased by $5.1 million to $13.1 million compared to a $8.0 million at December 31, 2013 primarily due to decreased cash from operations described above.

Contractual Obligations and Commitments

The following table presents information about our contractual obligations and commitments as of December 31, 2014, and the effects we expect such obligations to have on liquidity and cash flow in future periods. Some of the amounts below are estimates. We discuss these obligations and commitments elsewhere in this filing.

	Payments Due by Period
	Total		2015		2016-2017		2018-2019		After 2019
	(In thousands)
Long-term debt obligations (principal and interest)	$	1,337,552	$	85,081	$	167,229	$	317,615	$	767,627
Capital lease obligations (principal and interest)	117,054		41,927		67,271		7,659		197
Operating lease obligations	46,783		16,886		16,652		9,303		3,942
Other long-term liabilities(1)	1,574,772		60,638		127,771		156,623		1,229,740
Totals	$	3,076,161	$	204,532	$	378,923	$	491,200	$	2,001,506

_____________________

(1) Represents benefit payments for our postretirement medical benefits, black lung, workers’ compensation, and combined benefit fund plans, as well as contributions for our defined benefit pension plans and final reclamation costs.

Critical Accounting Policies

Postretirement Medical Benefits

We have an obligation to provide postretirement medical benefits to our former employees and their dependents. Detailed information related to this liability is included in Note 7 to our consolidated financial statements.

Our liability for our employees’ postretirement medical benefit costs is recorded on our consolidated balance sheets in amounts equal to the actuarially determined liability, as this obligation is not funded. We use various assumptions including the discount rate and future cost trends, to estimate the cost and obligation for this item. Our discount rate for postretirement medical benefit is determined by utilizing a hypothetical bond portfolio model, which approximates the future cash flows necessary to service our liability. This model is calculated using a yield curve that is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields. Our discount rates at December 31, 2014 ranged from 3.75% - 4.25% compared to a range of 4.50% - 5.05% at December 31, 2013. In 2014, our postretirement medical benefit liability increased $22.1 million. This increase was primarily driven by a $32.4 million increase due to decreases in discount rates and a $27.0 million increase due to updated mortality tables. These increases were partially offset with a $39.9 million decrease in liability primarily due to improved claims experience.

We make assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data and projecting forward the participant claims and our current benefit coverage. These projections include the continuation of cost savings we achieved in 2010 from the modernization of how we provide prescription drug benefits to retirees. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations.

The PPACA could potentially impact these benefits. The PPACA has both short-term and long-term implications on healthcare benefit plan standards. Implementation of this legislation is planned to occur in phases extending through 2018. We will continue to evaluate the impact of the PPACA in future periods as additional information, interpretations and guidance becomes available.

Below we have provided a sensitivity analysis to demonstrate the significance of the health care cost trend rate assumptions in relation to reported amounts.

72

	Postretirement Medical Benefits
Health Care Cost Trend Rate	1% Increase		1% Decrease
	(In thousands)
Effect on service and interest cost components	$	2,614	$	(2,096	)
Effect on postretirement medical benefit obligation	$	46,056	$	(37,003	)

Asset Retirement Obligations, Final Reclamation Costs and Reserve Estimates

Our asset retirement obligations primarily consist of cost estimates for final reclamation of surface land and support facilities at both surface mines and power plants in accordance with federal and state reclamation laws. Asset retirement obligations are based on projected pit configurations at the end of mining and are determined for each mine using estimates and assumptions including estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur such as mine plan revisions, changes in estimated costs, or changes in timing of the final reclamation activities, the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate to the changes. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different from currently estimated. Moreover, regulatory changes could increase our obligation to perform final reclamation and mine closing activities.

Certain of our customers have either agreed to reimburse us for final reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. See additional information regarding our asset retirement obligations in Note 10 to our consolidated financial statements.

Income Taxes and Deferred Income Taxes

As of December 31, 2014, we had significant deferred tax assets. Our deferred tax assets include federal and state regular net operating losses ("NOLs"), alternative minimum tax ("AMT)," credit carryforwards, ICTC carryforwards, and net deductible reversing temporary differences related to on-going differences between book and taxable income.

We believe we will be taxed under the AMT system for the foreseeable future due to the significant amount of statutory tax depletion in excess of book depletion expected to be generated by our mining operations. As a result, we have determined that a valuation allowance is required for all of our regular federal net operating loss carryforwards and AMT credit carryforwards since they are only available to offset future regular taxes. We have recorded a full valuation allowance for all of our state NOLs since we believe they will not be realized.

We have determined that a full valuation allowance is required for all of our ICTC carryforward. The ICTC can generally be used to offset AMT liability. We do not believe we have sufficient positive evidence to substantiate that our deferred tax asset for the ICTC carryforward is realizable at a more-likely-than-not level of assurance. As a result, we will continue to record a full valuation allowance on our ICTC carryforward.

We have determined that since our net deductible temporary differences will not reverse for the foreseeable future, and we are unable to forecast when we will have regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets.

The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations. The exception to that incremental approach is that all items (for example, items recorded in other comprehensive income, extraordinary items, and discontinued operations) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.

Business Combination Measurements

Acquisitions are accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value. The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.

73

Recent Accounting Pronouncements

The accounting standards adopted in 2014 did not have a material impact on our consolidated financial statements. See Note 1 to our consolidated financial statements for a discussion of recently adopted accounting pronouncements.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include financial instruments with off-balance sheet risk such as bank letters of credit and performance or surety bonds. We utilize surety bonds and letters of credit issued by financial institutions to third parties to assure the performance of our obligations relating to reclamation, workers’ compensation obligations, postretirement medical benefit obligations, and other obligations. These arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement medical benefit and other obligations as follows as of December 31, 2014:

	Reclamation Obligations		Workers’ Compensation Obligations		Post Retirement Medical Benefit Obligations		Other		Total
	(In thousands)
Surety bonds	$	353,675	$	9,113	$	9,068	$	12,160	$	384,016
Letters of credit	107,758		—		—		27,880		135,638
	$	461,433	$	9,113	$	9,068	$	40,040	$	519,654

During 2014 we added approximately $137.9 million of surety bonds and letters of credit related to reclamation and other financial obligations for our mines in Canada. In addition during 2014, we added approximately $38.0 million of surety bonds related to reclamation and other obligations for our mines in Ohio.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates, and credit risk.

Commodity Price Risk

We are exposed to commodity price risk on sales of power at our ROVA facility. We have entered into derivative contracts to purchase power in the future at fixed prices. Such derivative contracts are structured to manage our exposure to changing power prices and not for trading. For the year ended December 31, 2014 and 2013, we incurred losses related to these derivative contracts of $31.1 million and nil, respectively. Since any resales which we may make in the open market under these derivative contracts would be made at prevailing market prices, we may be subject to further losses under these hedging arrangements in the event that the market price for power falls below the level of our hedged position. Based on current market pricing trends, we may experience further losses under these hedging arrangements before the market price for power regains a level which is commensurate with our hedged position. If these trends continue, these losses could continue to adversely impact our results of operations and cash flows, and anticipated future cash losses are likely to be material. A sensitivity analysis has been performed to determine the incremental effect on future earnings related to open derivative instruments at December 31, 2014. A hypothetical 10 percent decrease in future power prices would decrease future earnings related to derivatives by $24.3 million. Similarly, a hypothetical 10 percent increase in future power prices would increase future earnings related to derivatives by $24.3 million.

We manage our price risk for coal sales through the use of long-term agreements, rather than through the use of derivatives. Nearly all of our coal is sold under long-term agreements. These coal contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted in accordance with changes in broad economic indicators such as the consumer price index, commodity-specific indices such as the PPI-light fuel oils index, and/or changes in our actual costs.

For our coal contracts which are not cost protected, we have exposure to price risk for supplies that are used in the normal course of production such as diesel fuel and explosives. We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time to time. At December 31, 2014, we had fuel supply contracts outstanding with a minimum purchase requirement of 4.5 million gallons of diesel fuel per year. These contracts qualify for the normal purchase normal sale exception under hedge accounting.

74

Interest Rate Risk

We are exposed to market risk associated with interest rates due to our existing indebtedness that is indexed to either prime rate or LIBOR. Our Term Loan had an outstanding balance of $350.0 million as of December 31, 2014 and has interest rates that fluctuate based on changes in market rates. An increase in the interest rates related to the Term Loan of 100 basis points would result in an annualized increase of $0.6 million in interest expense based on interest rates in effect at December 31, 2014. A decrease of 100 basis points would not have an effect. We have not historically used interest rate hedging instruments to manage our interest rate risk.

Credit Risk

We are exposed to credit loss in the event of non-performance by our counterparties. We attempt to manage this exposure by entering into agreements with counterparties that meet our credit standards and that are expected to fully satisfy their obligations under the contracts. These steps may not always be effective in addressing counterparty credit risk.

Foreign Currency Exchange Rates

We are exposed to the effects of changes in exchange rates primarily from the Canadian dollar at our Canadian operations. To address the risks arising from adverse changes in foreign currency exchange rates from our planned cash flows in the Canadian Acquisition we entered into various derivative contracts. All decisions on derivative contracts are authorized and executed pursuant to our policies and procedures, which do not allow the use of financial instruments for trading purposes. There were no foreign currency derivative contracts outstanding as of December 31, 2014.

75

ITEM 8 —FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Index to Financial Statements	Page
Report of Independent Registered Public Accounting Firm	77
Report of Independent Registered Public Accounting Firm	78
Consolidated Balance Sheets	79
Consolidated Statements of Operations	81
Consolidated Statements of Comprehensive Income (Loss)	82
Consolidated Statements of Shareholders’ Deficit	83
Consolidated Statements of Cash Flows	84
Notes to Consolidated Financial Statements	86

76

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Westmoreland Coal Company and subsidiaries

We have audited the accompanying consolidated balance sheets of Westmoreland Coal Company and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of Westmoreland Resources Partners, LP, a majority-owned subsidiary acquired on December 31, 2014, which reflects total assets constituting 17% of the related consolidated total as of December 31, 2014 and total revenue constituting 0% of the related consolidated total for the year then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Westmoreland Resources Partners, LP, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and, as to the balance sheet at December 31, 2014, the report of other auditors the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Westmoreland Coal Company and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 ended in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 6, 2015 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Denver, Colorado

March 6, 2015

77

Report of Independent Registered Public Accounting Firm

Board of Directors and Unitholders of

Westmoreland Resource Partners, LP

We have audited the accompanying consolidated balance sheets of Westmoreland Resource Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 (Successor) and Oxford Resource Partners, LP as of December 31, 2013 (Predecessor), and the related consolidated statements operations, partners’ capital (deficit) and cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor) (not presented herein). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Resource Partners, LP and subsidiaries as of December 31, 2014 (Successor) and December 31, 2013 (Predecessor), and the results of their operations and their cash flows for the period of December 31, 2014 (Successor) and the period from January 1, 2014 through December 31, 2014 and the two years in the period ended December 31, 2013 (Predecessor) in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 6, 2015

78

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

	December 31, 2014		December 31, 2013
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	14,258	$	61,110
Receivables:
Trade	143,052		66,196
Loan and lease receivables	10,493		—
Contractual third-party reclamation receivables	12,462		8,487
Other	19,923		5,086
	185,930		79,769
Inventories	133,855		39,972
Deferred income taxes	13,083		5,355
Restricted investments and bond collateral	—		5,998
Other current assets	13,645		12,835
Total current assets	360,771		205,039
Property, plant and equipment:
Land and mineral rights	500,226		278,188
Plant and equipment	956,112		657,696
	1,456,338		935,884
Less accumulated depreciation, depletion and amortization	528,676		445,848
Net property, plant and equipment	927,662		490,036
Loan and lease receivables	73,180		—
Advanced coal royalties	17,508		7,311
Reclamation deposits	77,907		74,921
Restricted investments and bond collateral	164,389		69,235
Contractual third-party reclamation receivables, less current portion	104,021		88,303
Investment in joint venture	33,409		—
Intangible assets, net of accumulated amortization of $15.3 million and $14.1 million at December 31, 2014 and December 31, 2013, respectively	31,315		1,520
Other assets	39,416		10,320
Total Assets	$	1,829,578	$	946,685

See accompanying Notes to Consolidated Financial Statements.

79

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

	December 31, 2014			December 31, 2013
	(In thousands)
Liabilities and Shareholders’ Deficit
Current liabilities:
Current installments of long-term debt	$	43,136		$	44,343
Revolving lines of credit	9,576			—
Accounts payable and accrued expenses:
Trade and other accrued liabilities	149,514			57,507
Interest payable	2,699			11,321
Production taxes	45,747			41,905
Workers’ compensation	671			717
Postretirement medical benefits	13,263			13,955
SERP	368			390
Deferred revenue	13,175			14,068
Asset retirement obligations	43,289			23,353
Other current liabilities	52,459			5,469
Total current liabilities	373,897			213,028
Long-term debt, less current installments	932,075			295,494
Workers’ compensation, less current portion	6,315			6,744
Excess of black lung benefit obligation over trust assets	11,252			8,675
Postretirement medical benefits, less current portion	293,156			270,374
Pension and SERP obligations, less current portion	49,779			24,176
Deferred revenue, less current portion	35,255			46,567
Asset retirement obligations, less current portion	409,456			256,511
Intangible liabilities, net of accumulated amortization of $13.5 million at December 31, 2014 and $12.4 million at December 31, 2013, respectively	4,538			5,606
Deferred income taxes	34,852			5,355
Other liabilities	28,448			2,034
Total liabilities	2,179,023			1,134,564
Shareholders’ deficit:
Preferred stock of $1.00 par value
Authorized 5,000,000 shares; Issued and outstanding 91,669 shares at December 31, 2014 and 159,960 shares at December 31, 2013, respectively	92			160
Common stock of $2.50 par value
Authorized 30,000,000 shares; Issued and outstanding 17,102,777 shares at December 31, 2014 and 14,592,231 shares at December 31, 2013, respectively	42,756			36,479
Other paid-in capital	185,644			134,861
Accumulated other comprehensive loss	(124,296		)	(63,595		)
Accumulated deficit	(468,902		)	(295,784		)
Total shareholders’ deficit	(364,706		)	(187,879		)
Noncontrolling interests in consolidated subsidiaries	15,261			—
Total deficit	(349,445		)	(187,879		)
Total Liabilities and Deficit	$	1,829,578		$	946,685

See accompanying Notes to Consolidated Financial Statements.

80

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Operations

	Years Ended December 31,
	2014			2013			2012
	(In thousands, except per share data)
Revenues	$	1,115,992		$	674,686		$	600,437
Cost, expenses and other:
Cost of sales	899,930			535,320			466,521
Depreciation, depletion and amortization	100,778			67,231			57,145
Selling and administrative	100,528			50,721			49,908
Heritage health benefit expenses	13,388			13,418			13,388
Loss (gain) on sales of assets	1,232			(74		)	528
Restructuring charges	14,989			5,078			—
Derivative loss	31,100			—			—
Income from equity affiliates	(3,159		)	—			—
Other operating loss (income)	181			(22,370		)	(15,925		)
	1,158,967			649,324			571,565
Operating income (loss)	(42,975		)	25,362			28,872
Other income (expense):
Interest expense	(84,234		)	(39,937		)	(42,677		)
Loss on extinguishment of debt	(49,154		)	(64		)	(1,986		)
Interest income	6,400			1,366			1,496
Loss on foreign exchange	(4,016		)	—			—
Other income	1,031			364			723
	(129,973		)	(38,271		)	(42,444		)
Loss before income taxes	(172,948		)	(12,909		)	(13,572		)
Income tax expense (benefit)	232			(4,782		)	90
Net loss	(173,180		)	(8,127		)	(13,662		)
Less net loss attributable to noncontrolling interest	(921		)	(3,430		)	(6,436		)
Net loss attributable to the Parent company	(172,259		)	(4,697		)	(7,226		)
Less preferred stock dividend requirements	859			1,360			1,360
Net loss applicable to common shareholders	$	(173,118	)	$	(6,057	)	$	(8,586	)
Net loss per share applicable to common shareholders:
Basic and diluted	$	(10.86	)	$	(0.42	)	$	(0.61	)
Weighted average number of common shares outstanding:
Basic and diluted	15,941			14,491			14,033

See accompanying Notes to Consolidated Financial Statements.

81

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)
Other comprehensive income (loss)
Pension and other postretirement plans:
Amortization of accumulated actuarial gains or losses, pension	983			3,490			2,960
Adjustments to accumulated actuarial losses and transition obligations, pension	(24,793		)	28,974			(9,812		)
Amortization of accumulated actuarial gains or losses, transition obligations, and prior service costs, postretirement medical benefits	18			4,005			2,572
Adjustments to accumulated actuarial gains, postretirement medical benefits	(19,442		)	53,230			(22,342		)
Tax effect of other comprehensive income gains	—			(4,892		)	—
Change in foreign currency translation adjustment	(17,880		)	—			—
Unrealized and realized gains and losses on available-for-sale securities	413			(57		)	(268		)
Other comprehensive income (loss)	(60,701		)	84,750			(26,890		)
Comprehensive income (loss) attributable to Westmoreland Coal Company	$	(233,881	)	$	76,623		$	(40,552	)

See accompanying Notes to Consolidated Financial Statements.

82

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Deficit

Years Ended December 31, 2012, 2013 and 2014

	Preferred Stock					Common Stock			Other Paid-In Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Non-controlling Interest			Total Shareholders’ Deficit
	Shares		Amount			Shares	Amount
	(In thousands, except shares data)
Balance at December 31, 2011	159,960		$	160		13,811,379	$	34,527	$	126,288		$	(121,455	)	$	(281,141	)	$	(8,237	)	$	(249,858	)
Preferred dividends declared	—		—			—	—		—			—			(1,360		)	—			(1,360		)
Common stock issued as compensation	—		—			323,432	808		5,232			—			—			—			6,040
Issuance of restricted stock	—		—			66,600	167		(668		)	—			—			—			(501		)
Net loss	—		—			—	—		—			—			(7,226		)	(6,436		)	(13,662		)
Other comprehensive loss	—		—			—	—		—			(26,890		)	—			—			(26,890		)
Balance at December 31, 2012	159,960		160			14,201,411	35,502		130,852			(148,345		)	(289,727		)	(14,673		)	(286,231		)
Preferred dividends declared	—		—			—	—		—			—			(1,360		)	—			(1,360		)
Common stock issued as compensation	—		—			224,129	560		4,762			—			—			—			5,322
Assumption of noncontrolling interest of subsidiary	—		—			—	—		—			—			—			18,103			18,103
Issuance of restricted stock	—		—			166,691	417		(753		)	—			—			—			(336		)
Net loss	—		—			—	—		—			—			(4,697		)	(3,430		)	(8,127		)
Other comprehensive income	—		—			—	—		—			84,750			—			—			84,750
Balance at December 31, 2013	159,960		160			14,592,231	36,479		134,861			(63,595		)	(295,784		)	—			(187,879		)
Preferred dividends declared	—		—			—	—		—			—			(859		)	—			(859		)
Common stock issued as compensation	—		—			47,386	116		5,966			—			—			—			6,082
Common stock options exercised	—		—			35,000	88		662			—			—			—			750
SARs exercised	—		—			16,130	40		(40		)	—			—			—			—
Conversion of preferred stock	(68,291	)	(68		)	466,537	1,168		(1,100		)	—			—			—			—
Common stock issued to pension plan assets	—		—			46,323	117		1,824			—			—			—			1,941
Offering shares	—		—			1,684,507	4,211		52,262			—			—			—			56,473
Issuance of restricted stock	—		—			214,663	537		(3,383		)	—			—			—			(2,846		)
Changes in WMLP ownership interest, net	—		—			—	—		(5,408		)	—			—			5,408			—
Westmoreland Resource Partners, LP acquisition	—		—			—	—		—			—			—			10,774			10,774
Net loss	—		—			—	—		—			—			(172,259		)	(921		)	(173,180		)
Other comprehensive loss	—		—			—	—		—			(60,701		)	—			—			(60,701		)
Balance at December 31, 2014	91,669		$	92		17,102,777	$	42,756	$	185,644		$	(124,296	)	$	(468,902	)	$	15,261		$	(349,445	)

See accompanying Notes to Consolidated Financial Statements.

83

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Cash flows from operating activities:
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	100,778			67,231			57,145
Accretion of asset retirement obligation and receivable	21,604			12,681			12,189
Non-cash tax benefits	—			(4,892		)	—
Amortization of intangible assets and liabilities, net	138			665			658
Share-based compensation	6,082			5,322			6,040
Loss (gain) on sales of assets	1,232			(74		)	528
Amortization of deferred financing costs	3,481			3,731			4,358
Other	1,087			(1,001		)	—
Loss on extinguishment of debt	49,154			64			1,986
Gain on sales of investment securities	(241		)	(3		)	(165		)
Loss on derivative instruments	31,100			—			—
Loss on foreign exchange	4,016			—			—
Pension settlement/curtailment accounting	2,651			—			—
Income from equity affiliates	(3,159		)	—			—
Distributions from equity affiliates	4,042			—			—
Changes in operating assets and liabilities:
Receivables	(403		)	(7,636		)	(12,855		)
Inventories	45,335			(2,512		)	(2,164		)
Excess of black lung benefit obligation over trust assets	2,577			319			1,791
Deferred income tax	(230		)	—			—
Accounts payable and accrued expenses	(37,763		)	13,579			17,399
Deferred revenue	(12,246		)	(9,078		)	(8,198		)
Income tax payable	1,674			(1		)	—
Accrual for workers’ compensation	(475		)	(2,069		)	(2,096		)
Asset retirement obligations	(7,661		)	(9,410		)	(6,943		)
Accrual for postretirement medical benefits	2,665			7,721			6,191
Pension and SERP obligations	(2,186		)	2,388			2,802
Other assets and liabilities	10,281			11,819			(7,860		)
Net cash provided by operating activities	50,353			80,717			57,144
Cash flows from investing activities:
Additions to property, plant and equipment	(50,326		)	(28,591		)	(21,032		)
Change in restricted investments and bond collateral and reclamation deposits	(52,514		)	1,434			(33,892		)
Cash payments in escrow for future acquisitions	(34,000		)	—			—
Cash payments related to acquisitions	(352,635		)	—			(72,522		)
Cash acquired related to acquisitions, net	8,173			—			—
Net proceeds from sales of assets	38,740			902			480
Proceeds from the sale of restricted investments	8,677			8,287			4,106

84

Payments related to loan and lease receivables	(5,682		)	—			—
Receipts from loan and lease receivables	8,039			—			—
Receivable from customer for property and equipment purchases	640			(389		)	(674		)
Other	(1,884		)	(3,540		)	—
Net cash used in investing activities	(432,772		)	(21,897		)	(123,534		)
Cash flows from financing activities:
Change in book overdrafts	141			310			(253		)
Borrowings from long-term debt, net of debt discount and premium	1,315,947			—			119,364
Repayments of long-term debt	(955,177		)	(28,088		)	(44,846		)
Borrowings on revolving lines of credit	25,000			7,000			16,500
Repayments on revolving lines of credit	(15,424		)	(7,000		)	(16,500		)
Debt issuance costs and other refinancing costs	(88,144		)	(182		)	(5,688		)
Preferred dividends paid	(859		)	(1,360		)	(1,360		)
Proceeds from issuance of common shares	56,473			—			—
Exercise of stock options	749			—			—
Net cash provided by (used in) financing activities	338,706			(29,320		)	67,217
Effect of exchange rate changes on cash	(3,139		)	—			—
Net increase (decrease) in cash and cash equivalents	(46,852		)	29,500			827
Cash and cash equivalents, beginning of year	61,110			31,610			30,783
Cash and cash equivalents, end of year	$	14,258		$	61,110		$	31,610
Supplemental disclosures of cash flow information:
Cash paid for interest	$	85,047		$	36,252		$	34,380
Cash paid (received) for income taxes	117			111			(73		)
Non-cash transactions:
Accrued purchases of property and equipment	11,740			1,112			634
Capital leases and other financing sources	15,599			5,371			1,828

See accompanying Notes to Consolidated Financial Statements.

85

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Westmoreland Coal Company, or the Company, Westmoreland, WCC, or the Parent, is an energy company. The Company’s current principal activities are conducted within the United States and Canada. U.S. activities include the production and sale of coal from its mines in Montana, Wyoming, North Dakota, Texas, and Ohio and the ownership of the Roanoke Valley power plants, or ROVA, in North Carolina. Canadian activities include the production and sale of coal from six surface mines in Alberta and Saskatchewan, selling char to the barbecue briquette industry, and a 50% interest in an activated carbon plant. The Company’s activities are primarily conducted through wholly owned subsidiaries.

U.S. Operations – The Company’s Kemmerer Mine is owned by its subsidiary Westmoreland Kemmerer, Inc., or Kemmerer. The Company’s Absaloka Mine is owned by its subsidiary Westmoreland Resources, Inc., or WRI. The Beulah, Jewett, Rosebud, and Savage Mines are owned through the Company’s subsidiary Westmoreland Mining LLC, or WML.

Canadian Operations – Prairie Mines & Royalty ULC ("PMRU") operates five surface coal mines in Alberta and Saskatchewan. PMRU owns and operates the Paintearth, Sheerness, Genesee, Poplar River and Estevan mines. PMRU directly owns a 50% joint venture interest in the Estevan Activated Carbon Joint Venture, at the Estevan mine, which produces activated carbon for the removal of mercury from flue gas. PMRU also sells char to the barbecue briquette industry. Coal Valley Resources Inc., "CVRI" operates the Coal Valley Mine which is a surface mine located in West Central Alberta where the majority of coal is exported overseas to Asian utility companies and commodity traders. CVRI operated the Obed Mountain surface mine, which ceased production in 2013 and is currently in reclamation.

Master Limited Partnership - On December 31, 2014, the Company acquired 100% of the outstanding units of Westmoreland Resources GP, LLC (formerly Oxford Resources GP, LLC) (the “GP”), the general partner of Westmoreland Resource Partners, LP (formerly Oxford Resource Partners, LP) (NYSE: WMLP, “WMLP”). Concurrent with the acquisition of the GP, Westmoreland contributed certain royalty-bearing coal reserves to WMLP in return for units issued by WMLP giving the Company an approximately 79% interest in WMLP. WMLP is a low-cost producer of high value steam coal in Northern Appalachia. WMLP markets its coal primarily to large electric utilities with coal-fire, base load scrubbed power plants under long-term coal sales contracts. See Note 2 for additional information.

Consolidation Policy

The Consolidated Financial Statements of Westmoreland Coal Company include the accounts of the Company and its controlled subsidiaries. The Company consolidates any variable interest entity, or VIE, for which the Company is considered the primary beneficiary. The Company provides for noncontrolling interests in consolidated subsidiaries, in which the Company’s ownership is less than 100 percent. All intercompany accounts and transactions have been eliminated.

A VIE is an entity that is unable to make significant decisions about its activities or does not have the obligation to absorb losses or the right to receive returns generated by its operations. If the entity meets one of these characteristics, then the Company must determine if it is the primary beneficiary of the VIE. The party exposed to the majority of the risks and rewards with the VIE is the primary beneficiary and must consolidate the entity.

The Company has determined prior to December 31, 2013, it was the primary beneficiary in Absaloka Coal LLC, a VIE, in which it held less than a 50% ownership through December 31, 2013. The Company has consolidated this entity within the coal segment. The investment in Absaloka Coal LLC by its outside partner did not continue after December 31, 2013, and beginning in 2014, Absaloka Coal LLC is 100% owned by the Company, but ceased to have operations. As a result, the Company has unwound the transaction as of December 31, 2013 and concerning our balance sheet have decreased Other liabilities by $19.1 million and decreased Noncontrolling interest by $18.1 million. As a result, as of December 31, 2013, the noncontrolling interest was eliminated.

The Company owns 100% of the GP equity units and thereby has controlling interest of WMLP. The Company includes the accounts of the GP and provides for a noncontrolling interest in WMLP, which was approximately 21% at December 31, 2014.

The Company's 50% interest in the Estevan Activated Carbon Joint Venture is accounted for under the equity method of accounting. Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, are accounted for under the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in Income from equity affiliates on the Consolidated Statements of Operations with a corresponding entry to increase or decrease the carrying value of the investment.

86

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximate fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Trade Receivables

Trade receivables are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on a review of collectability. The Company has determined that no allowance is necessary for trade receivables as of December 31, 2014 and 2013.

Loan and Lease Receivables

The Company periodically executes loans and finance leases at the Genesee Mine with its only customer for purposes of funding capital expenditures and working capital requirements. Finance lease and loan receivables are measured at the present value of the future lease payments at the inception of the arrangement. Lease payments received are comprised of a repayment of principal and finance income. Finance income is recognized based on the interest rate implicit in the finance lease. PMRU recognizes finance income over periods between three and twenty-seven years , which reflect a constant periodic return on its net investment in the finance lease. Initial direct costs are included in the initial measurement of the finance lease receivables and reduce the amount of income recognized over the lease term.

Inventories

Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, depreciation, depletion, amortization, operating overhead and other related costs.

Exploration and Mine Development

Exploration expenditures are charged to Cost of sales as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, relocate equipment, build or improve existing haul roads and create the initial pre-production box cut to remove overburden for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices. Once production has begun, mining costs are then expensed as incurred.

Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost and includes long-term spare parts inventory. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses.

Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:

87

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	Years
Buildings and improvements	5 to 40
Machinery and equipment	3 to 36

Long-term spare parts inventory begins depreciation when placed in service.

The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.

Other Current Receivables and Other Current Liabilities

Upon acquisition of CVRI in 2014, the Company became responsible for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. The prior owner, Sherritt International Corporation, has indemnified Westmoreland against past and future liability stemming from the incident. As of December 31, 2014, the Company has recorded $16.2 million in Other current liabilities for the estimated costs of remediation work and a corresponding amount in Other current receivables to reflect the indemnification by the prior owner of CVRI.

Reclamation Deposits and Contractual Third-Party Reclamation Receivables

Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. Amounts received from customers and held on deposit are recorded as reclamation deposits. Amounts that are reimbursable by customers are recorded as third-party reclamation receivables when the related reclamation obligation is recorded.

Financial Instruments

The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception or instruments that contain features that qualify them as embedded derivatives. Except for derivatives that qualify for the normal purchase normal sale exception, all derivative financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or Accumulated other comprehensive income (loss) if they qualify for cash flow hedge accounting.

Held-to-maturity financial instruments consist of non-derivative financial assets with fixed or determinable payments and a fixed term, which the Company has the ability and intent to hold until maturity, and, therefore, accounts for them as held-to-maturity securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned.

The Company has securities classified as available-for-sale, which are recorded at fair value. The changes in fair values are recorded as unrealized gains (losses) as a component of Accumulated other comprehensive income (loss) in shareholders’ deficit.

The Company reviews its securities routinely for other-than-temporary impairment. The primary factors used to determine if an impairment charge must be recorded because a decline in value of the security is other than temporary include (i) whether the fair value of the investment is significantly below its cost basis, (ii) the financial condition of the issuer of the security, (iii) the length of time that the cost of the security has exceeded its fair value and (iv) the Company’s intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in market value. Other-than-temporary impairments are recorded as a component of Other income (expense).

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a given measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs.

Fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value and is defined as:

88

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

• Level 1, defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities generally valued based on independent third-party market prices.

• Level 2, defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

• Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Company’s non-recurring fair value measurements include asset retirement obligations and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to reclamation liabilities using level 3 inputs. The significant inputs used to calculate such liabilities includes estimates of costs to be incurred, the Company’s credit adjusted discount rate, inflation rates and estimated dates of reclamation. The asset retirement liability is accreted to its present value each period and the associated mineral rights are depleted using the units-of-production method.

The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors.

See Notes 4, 7, 8, 10, 11 and 12 for further disclosures related to the Company’s fair value estimates.

Intangible Assets and Liabilities

Identifiable intangible assets or liabilities acquired in a business combination must be recognized and reported separately from goodwill. Intangible assets result from more favorable market prices than contracted prices as measured during a business combination. Intangible liabilities result from less favorable market prices than contracted prices as measured during a business combination. Substantially all of these intangible assets and liabilities are amortized on a straight-line basis over the respective period of the agreements.

Amortization of intangible assets recognized in Cost of sales was $1.2 million in 2014 and $1.7 million in 2013, and 2012. Amortization of intangible liabilities recognized in Revenues was $1.0 million in 2014, 2013, and 2012.

The estimated aggregate amortization amounts from intangibles assets and liabilities for each of the next five years as of December 31, 2014 are as follows:

	Amortization Expense
	(In thousands)
2015	$	1,073
2016	1,073
2017	1,073
2018	1,073
2019	1,820

Workers’ Compensation Benefits

The Company is self-insured for workers’ compensation claims incurred prior to 1996. The liabilities for workers’ compensation claims are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience. Adjustments to the probable ultimate liabilities are made annually based on subsequent developments and experience and are included in operations at the time of the revised estimate.

The Company insures its current employees through third-party insurance providers and state arrangements.

89

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Pneumoconiosis (Black Lung) Benefits

The Company is self-insured for federal and state black lung benefits for former heritage employees and has established an independent trust to pay these benefits. The Company accounts for these benefits on the accrual basis. An independent actuary annually calculates the present value of the accumulated black lung obligation. The underfunded status in 2014 and 2013 of the Company’s obligation is included as Excess of black lung benefit obligation over trust assets in the accompanying consolidated balance sheets. Actuarial gains and losses are recognized in the period in which they arise.

The Company insures its current represented employees through arrangements with its unions and its current non-represented employees are insured through third-party insurance providers.

Postretirement Health Care Benefits

The Company accrues the cost to provide the benefits over the employees’ period of active service for postretirement benefits other than pensions. These costs are determined on an actuarial basis. The Company’s consolidated balance sheet reflects the unfunded status of postretirement benefit obligations.

Pension and SERP Plans

The Company accrues the cost to provide the benefits over the employees’ period of active service for the non-contributory defined benefit pension and SERP plans it sponsors. These costs are determined on an actuarial basis. The Company’s consolidated balance sheet reflects the unfunded status of the defined benefit pension and SERP plans.

Deferred Revenue

Deferred revenues represent funding received upon the negotiation of long-term contracts. The deferred revenues for coal will be recognized as deliveries of the reserved coal are made in accordance with the long-term coal contracts. Deferred power revenues are recognized on a pro rata basis, based on the payments estimated to be received over the remaining term of the power sales agreements.

Asset Retirement Obligations

The Company’s asset retirement obligation, or ARO, liabilities primarily consist of estimated costs to reclaim surface land and support facilities at its mines and power plants in accordance with federal and state reclamation laws as established by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations at the end of mining and are escalated for inflation, and then discounted at a credit-adjusted risk-free rate. The Company records mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO liability is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities.

Income Taxes

The Company is subject to income taxes in the U.S. (including federal and state) and certain foreign jurisdictions. Deferred income taxes are provided for temporary differences arising from differences between the financial statement amount and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates anticipated to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not (greater than 50%) that a deferred tax asset will not be realized. In determining the need for a valuation allowance at each reporting period, the Company considers projected realization of tax benefits based on expected levels of future taxable income, the duration of statutory carryforward periods, experience with operating loss and tax credit carryforwards not expiring and availability of tax planning strategies.

Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on the derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The Company includes interest and penalties related to income tax matters in income tax expense.

90

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations. The exception to that incremental approach is that all items (for example, items recorded in other comprehensive income, extraordinary items, and discontinued operations) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the effective interest method. These amounts are recorded in Other assets in the accompanying consolidated balance sheets.

Coal Revenues

The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales revenue is recognized based on the pricing contained in the contracts in place at the time that title passes.

Power Revenues

ROVA supplies power it produces and generates revenues from such sales, as well as through the settlement of related purchased power arrangements. ROVA may supply its customer substitute power not produced by ROVA during periods when it is uneconomical to operate the ROVA units. While the Company expects to continue to operate ROVA during high demand periods, the Company expects the facility to remain idle during low demand periods, during which it will meet the customer's power needs by purchasing power from a third party provider at a fixed price. Alternatively, the Company has the option to operate the ROVA units, sell its produced power to its customer and resell the purchased power into the open market.

A portion of the payment under the power sales agreement is considered to be an operating lease. The Company is recognizing these amounts previously invoiced as revenue on a pro rata basis over the remaining term of the power sales agreement. Under this method of recognizing revenue, $9.6 million and $8.7 million of previously deferred revenue was recognized during 2014 and 2013, respectively.

Other Operating Income (Loss)

Other operating income in the accompanying Consolidated Results of Operations reflects income from sources other than coal or power revenues. Income from the Company’s Indian Coal Tax Credit monetization transaction is recorded as Other operating income. The Company recognizes income as business interruption losses are incurred and reimbursement is virtually assured and has recognized $16.2 million and $17.3 million of income during 2013 and 2012, respectively; which is included in Other operating income. Insurance proceeds are included in Net cash provided by operating activities.

Share-Based Compensation

Share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire award. These costs are recorded in Cost of sales and Selling and administrative expenses in the accompanying consolidated results of operations.

Earnings (Loss) per Share

Basic earnings (loss) per share have been computed by dividing the net income (loss) applicable to common shareholders by the weighted average number of shares of common stock outstanding during each period. Net income (loss) applicable to common shareholders includes the adjustment for net income or loss attributable to noncontrolling interest. Diluted earnings (loss) per share is computed by including the dilutive effect of common stock that would be issued assuming conversion or exercise of outstanding convertible notes, stock options, stock appreciation rights, restricted stock and warrants. No such items were included in the computation of diluted loss per share for the years ended 2014, 2013 or 2012 because the Company incurred a loss from operations in each of these periods and the effect of inclusion would have been anti-dilutive.

91

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The table below shows the number of shares that were excluded from the calculation of diluted loss per share because their inclusion would be anti-dilutive to the calculation:

	Years Ended December 31,
	2014	2013	2012
	(In thousands)
Convertible notes and securities	626	1,093	1,093
Restricted stock units, stock options, and SARs	537	805	978
Total shares excluded from diluted shares calculation	1,163	1,898	2,071

Derivatives

The Company enters into financial derivatives to manage exposure to fluctuations in foreign currency exchange rates and power prices. The Company does not utilize derivative financial instruments for trading purposes or for speculative purposes.

The Company’s derivative instruments are recorded at fair value with changes in fair value recognized in the Consolidated Statements of Operations at the end of each period in Loss on foreign exchange or Derivative loss.

Foreign Exchange Transactions

Amounts held and transactions denominated in foreign currencies other than the operating unit’s functional currency give rise to foreign exchange gains and losses which are included within Loss on foreign exchange.

Foreign Currency Translation

The functional currency of the Company’s Canadian operations is the Canadian dollar. The Company’s Canadian operations’ assets and liabilities are translated at period end exchange rates, and revenues and costs are translated using average exchange rates for the period. Foreign currency translation adjustments are reported in Other comprehensive income.

Reclassifications

Certain amounts in prior periods have been reclassified to conform with the presentation of 2014, with no effect on previously reported net loss, cash flows or shareholders’ deficit. The reclassification affected accounts within current assets, current liabilities and noncurrent liabilities on the Consolidated Balance Sheet.

Recently Adopted Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification (ASC) Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the effect that adopting this new accounting guidance will have on its consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU 2014-15 Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard provides guidance around management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Company's financial statements.

Liquidity and Capital Resources

The Parent is a holding company and conducts its operations through subsidiaries. The Parent has significant cash requirements to fund debt obligations, ongoing heritage health benefit costs, pension contributions, and corporate overhead expenses. The principal sources of cash flow to the Parent are distributions from its principal operating subsidiaries. The cash at

92

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

all of its subsidiaries is immediately available, except WRMI and WMLP. The cash at its captive insurance entity, WRMI, is available through dividends and is subject to maintaining a statutory minimum level of capital, which is two hundred fifty thousand dollars. The cash at WMLP is available through distributions. WMLP intends to resume quarterly distributions of $0.20 per unit beginning in April 2015, or $4.6 million annually. Based on the Company's current ownership of WMLP, the Company would expect to receive approximately 79% of WMLP’s distributions.

Under the Company's revolving credit agreement, the maximum available borrowing amount is $50 million, to which the maximum principal amount available for borrowings under the credit agreement can be increased to $100 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce the balance available under the revolver. At December 31, 2014, availability on the revolver was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit.

The Company anticipates that with the $75 million increase to the Term Loan Facility that closed on January 22, 2015, cash from operations, cash on hand and available borrowing capacity will be sufficient to meet its investing, financing, and working capital requirements for the foreseeable future.

2. ACQUISITIONS

Acquisition of General Partner of Westmoreland Resource Partners, LP

On December 31, 2014, the Company completed the acquisition of Westmoreland Resources GP, LLC, the general partner of Westmoreland Resource Partners, LP and completed a contribution of certain royalty-bearing coal reserves to WMLP in return for WMLP common units (the “Contribution”).

The completion of the GP acquisition and the Contribution provide Westmoreland with a platform to implement a value-creating drop-down strategy, pursuant to which it intends to periodically contribute certain U.S. and Canadian coal assets to WMLP in exchange for a combination of cash and additional limited partner interests. Westmoreland expects these transactions to unlock value that is inherent in Westmoreland’s stable cash flow-generating business model, to the benefit of both its stakeholders and WMLP’s unitholders. WMLP will continue to operate as a standalone, publicly traded master limited partnership, with Westmoreland owning approximately 79% of the fully diluted limited partner interests. WMLP intends to resume quarterly distributions of $0.20 per unit beginning in April 2015, or $4.6 million annually. Based on the Company's current ownership of WMLP, it would expect to receive approximately 79% of WMLP’s distributions. In addition as WMLP's general partner, the Company is entitled to incentive distribution rights.

Westmoreland paid $30.0 million in December, 2014 and $3.5 million in January, 2015 to acquire the GP; and received 4,512,500 common units of WMLP (on a post-split basis following a 12-to-1 reverse split of WMLP’s common and general partner units) as consideration for the Contribution.

In connection with the closing, the WMLP’s name was changed to Westmoreland Resource Partners, LP from Oxford Resource Partners, LP and the name of the GP was changed to Westmoreland Resources GP, LLC from Oxford Resources GP, LLC. The common units of WMLP on the NYSE under the symbol “WMLP”.

Acquisition related costs of $4.5 million have been expensed for the year ended December 31, 2014 which are included in Selling and administrative costs.

The acquisition of the GP has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value.

The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.

93

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

A summary of the purchase consideration and a preliminary allocation of the purchase consideration follows (in millions):

Purchase Price:
Cash paid at closing	$	30.0
Contingent consideration	3.5
Fair value of outstanding WMLP units (1)	10.8
Total purchase consideration	$	44.3
Preliminary allocation of purchase price:
Assets:
Trade receivables and other	$	22.5
Inventories - materials and supplies	7.4
Inventories - coal	6.6
Other current assets	1.3
Total current assets	37.8
Land and mineral rights	38.6
Plant and equipment	134.0
Advanced coal royalties	9.2
Restricted investments and bond collateral	10.6
Intangible assets	31.0
Other assets	0.2
Total Assets	261.4
Liabilities:
Trade payables and other accrued liabilities	(19.1		)
Asset retirement obligations	(7.8		)
Other current liabilities	(4.0		)
Total current liabilities	(30.9		)
Long-term debt, less current installments	(160.1		)
Asset retirement obligations, less current portion	(23.9		)
Warrants	(2.0		)
Other liabilities	(0.2		)
Total Liabilities	(217.1		)
Net Assets	44.3
Non-controlling Interest	(10.8		)
Invested Equity	$	33.5

(1) Represents the market price of WMLP units outstanding using the December 31, 2014 closing price of $1.00.

No goodwill was recorded in the acquisition and $31.0 million of intangible assets to be amortized over a 15-year period were identified in the acquisition. The intangible asset identified in the acquisition is a favorable terminal lease at a dock in Ohio which was fair valued based on more favorable market prices than contracted prices in lease agreements as measured during a business combination.

Canadian Acquisition

On December 24, 2013, the Company entered into an agreement to acquire Sherritt International Corporation’s Prairie and Mountain coal mining operations, collectively referred to as the Canadian Acquisition. On April 28, 2014, Westmoreland Coal Company consummated the Canadian Acquisition. These operations, referred to as the Canadian operations, include six producing thermal coal mines in the Canadian provinces of Alberta and Saskatchewan, a char production facility, and a 50%

94

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

interest in an activated carbon plant. The purchase consideration included a $282.8 million initial cash payment made on April 28, 2014, a cash payment for a working capital adjustment of $39.8 million made on June 25, 2014, and assumed liabilities of $421.3 million.

Acquisition related costs of $33.6 million have been expensed for the year ended December 31, 2014; which include a $14.2 million charge to Cost of sales related to the sale of inventory written up to fair value in the acquisition, $8.3 million of expenses included in Selling and administrative costs, $6.2 million of loss on foreign exchange as described in Note 11, and $4.9 million included in Interest expense related to a bridge facility commitment fee.

The Canadian Acquisition has been accounted for under the acquisition method of accounting that requires the total purchase consideration to be allocated to the assets acquired and liabilities assumed based on estimates of fair value.

The Company has finalized the purchase price allocation for the Canadian Acquisition. No goodwill was recorded in the acquisition and $37.0 million of intangible assets were identified in the acquisition.

95

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

A summary of the purchase consideration and allocation of the purchase consideration follows (in millions):

	Provisional as of June 30, 2014			Adjustments			Final as of December 31, 2014
Purchase Price:
Cash paid - Initial payment	$	282.8		$	—		$	282.8
Cash paid - Working capital adjustment	39.8			—			39.8
Total cash consideration	$	322.6		$	—		$	322.6
Allocation of purchase price:
Assets:
Cash and cash equivalents	$	26.2		$	—		$	26.2
Receivables	49.9			28.2			78.1
Inventories - materials and supplies	52.0			—			52.0
Inventories - coal	79.8			—			79.8
Loan and lease receivables	11.2			—			11.2
Deferred tax assets	6.7			1.5			8.2
Other current assets	3.4			—			3.4
Total current assets	229.2			29.7			258.9
Land and mineral rights	151.3			51.3			202.6
Plant and equipment	139.6			(24.8		)	114.8
Loan and lease receivables	83.8			(4.7		)	79.1
Contractual third-party reclamation receivables, less current portion	6.8			—			6.8
Investment in joint venture	32.1			3.9			36.0
Intangible assets	—			37.0			37.0
Other assets	10.3			(1.6		)	8.7
Total Assets	653.1			90.8			743.9
Liabilities:
Current installments of long-term debt	(36.3		)	—			(36.3		)
Trade payables and other accrued liabilities	(93.7		)	(42.4		)	(136.1		)
Asset retirement obligations	(9.7		)	1.9			(7.8		)
Total current liabilities	(139.7		)	(40.5		)	(180.2		)
Long-term debt, less current installments	(86.3		)	—			(86.3		)
Asset retirement obligations, less current portion	(92.4		)	(30.5		)	(122.9		)
Deferred tax liabilities	(12.1		)	(19.8		)	(31.9		)
Total Liabilities	(330.5		)	(90.8		)	(421.3		)
Net fair value	$	322.6		$	—		$	322.6

The $26.2 million of cash and cash equivalents noted above includes $18.1 million which was used for immediate payment of an assumed liability on the acquisition date, leaving $8.1 million of net cash received upon the acquisition.

During the third quarter of 2014, the Company transferred to an unrelated third party the contract related to the $37.0 million intangible asset noted above. Proceeds of $37.0 million were received from the unrelated third party, with no gain or loss recognized on the transaction.

The Company became responsible for remediation work for a breach on a containment pond at a currently inactive mine that occurred on October 31, 2013. The prior owner, Sherritt International Corporation, has indemnified Westmoreland

96

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

against past and future liability stemming from the incident. Accordingly, an indemnification asset of $27.9 million and a corresponding liability was recorded at April 28, 2014.

The results of operations of the Canadian operations from the acquisition date of April 28, 2014 have been included in the Company’s consolidated results of operations for the year ended December 31, 2014. The Canadian operations generated $388.7 million of revenue and $2.7 million of operating loss since the April 28, 2014 acquisition date.

Unaudited Pro Forma Information

The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the acquisition of the GP and the Canadian Acquisition occurred on January 1, 2013. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable, however, they are not necessarily indicative of the consolidated results of operations had the acquisitions occurred on January 1, 2013, or of future results of operations.

	Years Ended
	December 31, 2014			December 31, 2013
	(In thousands)
Total Revenues
As reported	$	1,115,992		$	674,686
Pro forma (unaudited)	$	1,644,474		$	1,673,538
Operating Income (Loss)
As reported	$	(42,975	)	$	25,362
Pro forma (unaudited)	$	(38,827	)	$	36,097
Net loss applicable to common shareholders
As reported	$	(173,118	)	$	(6,057	)
Pro forma (unaudited)	$	(135,647	)	$	(62,595	)
Net loss per share applicable to common shareholders
As reported	$	(10.86	)	$	(0.42	)
Pro forma (unaudited)	$	(8.51	)	$	(4.32	)

3. INVENTORIES

Inventories consisted of the following:

	December 31,
	2014			2013
	(In thousands)
Coal stockpiles	$	41,795		$	543
Coal fuel inventories	6,531			6,161
Materials and supplies	88,584			34,233
Reserve for obsolete inventory	(3,055		)	(965		)
Total	$	133,855		$	39,972

97

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

4. RESTRICTED INVESTMENTS AND BOND COLLATERAL

The Company’s restricted investments and bond collateral consist of the following:

	December 31,
	2014		2013
	(In thousands)
Coal - U.S. Segment:
WML debt reserve account	$	—	$	13,067
Reclamation bond collateral:
Kemmerer Mine	25,282		24,966
Absaloka Mine	11,781		11,653
Rosebud Mine	3,145		3,145
Beulah Mine	1,270		1,270
Buckingham acquisition escrow	34,000		—
Coal - Canada Segment:
PMRU	18,199		—
CVRI	31,866		—
Coal - WMLP Segment:
WMLP	10,634		—
Power Segment:
Letter of credit account	—		5,998
Power contract collateral	12,600		—
Corporate Segment:
Postretirement medical benefit bonds	8,780		8,467
Workers’ compensation bonds	6,832		6,667
Total restricted investments and bond collateral	164,389		75,233
Less current portion	—		(5,998		)
Total restricted investments and bond collateral, less current portion	$	164,389	$	69,235

For all of its restricted investments and bond collateral accounts, the Company can select from limited fixed-income investment options for the funds and receive the investment returns on these investments. Funds in the restricted investments and bond collateral accounts are not available to meet the Company’s general cash needs.

These accounts include available-for-sale securities. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive loss.

The cost basis of an investment sold is specifically identified.

During the year ended December 31, 2014, the Company decided to more actively manage its investment yields. This decision resulted in the sale of $5.1 million carrying value of securities and realized gains of less than $0.1 million during the year ended December 31, 2014 that were previously designated as held-to-maturity. The Company transferred the remainder of its securities classified as held-to-maturity to available-for-sale securities. The carrying value of held-to-maturity securities held as Restricted investments and bond collateral transferred to available-for-sale during the year ended December 31, 2014 was $34.5 million. As a result of the transfer, the Company recorded $0.6 million of unrealized holding gains in Accumulated other comprehensive loss during the year ended December 31, 2014.

The Company’s carrying value and estimated fair value of its restricted investments and bond collateral at December 31, 2014 are as follows:

98

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	Carrying Value		Fair Value
	(In thousands)
Cash and cash equivalents	$	127,881	$	127,881
Time deposits	2,451		2,451
Available-for-sale	34,057		34,057
	$	164,389	$	164,389

In 2014, 2013, and 2012, the Company recorded a gain of $0.3 million, less than $0.1 million, and $0.1 million, respectively, on the sale of available-for-sale securities held as restricted investments and bond collateral.

The $6.0 million letter of credit account in the power segment was released from restriction in February, 2014.

Coal Segments

As of December 31, 2014, the Company had reclamation bond collateral in place for the individual Mines as required. These government-required bonds assure that coal-mining operations comply with applicable federal and state regulations relating to the performance and completion of final reclamation activities. The amounts deposited in the bond collateral account secure the bonds issued by the bonding company.

Power Segment

As of February, 2014, the Company was no longer required to fund a letter of credit account for its power operations. The Company will periodically need to fund a power contract collateral account related to its contracts to purchase power.

Corporate Segment

The Company is required to obtain surety bonds in connection with its self-insured workers’ compensation plan and certain health care plans. The Company’s surety bond underwriters require collateral to issue these bonds.

Held-to-Maturity and Available-for-Sale Restricted Investments and Bond Collateral

The amortized cost, gross unrealized holding gains and losses and fair value of held-to-maturity securities are as follows:

	December 31,
	2014		2013
	(In thousands)
Amortized cost	$	—	$	32,184
Gross unrealized holding gains	—		309
Gross unrealized holding losses	—		(447		)
Fair value	$	—	$	32,046

The cost basis, gross unrealized holding gains and fair value of available-for-sale securities are as follows:

	December 31,
	2014			2013
	(In thousands)
Cost basis	$	33,879		$	—
Gross unrealized holding gains	761			—
Gross unrealized holding losses	(583		)	—
Fair value	$	34,057		$	—

99

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Maturities of available-for-sale securities were as follows at December 31, 2014:

	Amortized Cost		Fair Value
	(In thousands)
Due within one year	$	327	$	331
Due in five years or less	13,961		13,996
Due after five years to ten years	11,323		11,440
Due in more than ten years	8,268		8,290
	$	33,879	$	34,057

5. RESTRUCTURING CHARGES

In 2013, the Company entered into an agreement with Dominion Virginia Power, a subsidiary of Dominion, to renegotiate the remaining 5 years of the ROVA contract. The Company recorded a restructuring charge for additional contractual obligations of $0.5 million for the year ended December 31, 2014. The Company expects that the $0.4 million of accruals as of December 31, 2014 will be paid out in first quarter of 2015.

The table below represents the restructuring provision activity related to the ROVA restructuring affecting our Power segment during the year ended December 31, 2014 (in millions):

Beginning Balance		Restructuring Charges		Restructuring Payments		Ending Balance
$	5.1	$	0.5	$	5.2	$	0.4

During 2014, the Company initiated strategic changes related to the Canadian Acquisition and the Westmoreland Resources GP, LLC Acquisition. The restructuring actions were completed in 2014 for the Canadian Acquisition and are expected to be completed in 2015 for the Westmoreland Resources GP, LLC Acquisition. The Company recorded restructuring charges for one-time employee termination benefits of $14.5 million for the year ended December 31, 2014 and expects that accruals will be paid through 2016.

The table below represents the restructuring provision activity related to the Canadian Acquisition and the Westmoreland Resources GP, LLC Acquisition affecting our Coal - Canada, Coal - U.S. and Coal - WMLP segments during the year ended December 31, 2014 (in millions):

Beginning Balance		Restructuring Charges		Restructuring Payments		Ending Balance
$	—	$	14.5	$	5.7	$	8.8

100

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

6. LINES OF CREDIT AND LONG-TERM DEBT

The amounts outstanding under the Company’s long-term debt consisted of the following as of the dates indicated:

	Total Debt Outstanding December 31,
	2014			2013
	(In thousands)
8.75% senior secured notes due 2021	$	350,000		$	—
Term loan facility due 2020	350,000			—
WMLP term loan facility due 2018	175,000			—
10.75% senior notes	—			251,500
8.02% WML term debt	—			85,500
Capital lease obligations	109,351			10,153
Revolving line of credit	9,576			—
Other	4,062			1,209
Debt discount	(13,202		)	(8,525		)
Total debt outstanding	984,787			339,837
Less current installments	(52,712		)	(44,343		)
Total debt outstanding, less current installments	$	932,075		$	295,494

The following table presents aggregate contractual debt maturities of all long-term debt:

	As of December 31, 2014
	(In thousands)
2015	$	52,712
2016	41,489
2017	31,435
2018	183,848
2019	5,808
Thereafter	682,697
Total	997,989
Less: debt discount	(13,202		)
Total debt	$	984,787

8.75% Notes Offering

On December 16, 2014 (the “Closing Date”), the Company completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the Term Loan Credit Facility Obligations defined below under “Term Loan Credit Agreement,” and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. Proceeds from the 8.75% Notes offering and borrowing on the Term Loan Credit Agreement were used to repay the outstanding 10.75% senior notes with a principal balance of $675.5 million. As a result of the extinguishment of the 10.75% senior notes, the Company recorded a $34.9 million loss on extinguishment of debt. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.

The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the Indenture, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the Indenture. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the

101

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

principal amount of the 8.75% Notes to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by Westmoreland Resources GP, LLC or Westmoreland Resource Partners, LP, referred to as the Non-guarantors.

The 8.75% Notes and the guarantees are secured equally and ratably with the Term Loan Credit Agreement (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the Revolving Credit Agreement (as defined below), a second priority lien on substantially all cash, accounts and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the Term Loan Credit Agreement, who hold identical first and second priority liens, as applicable, on the Notes Collateral.

The Indenture restricts the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.

The Indenture contains, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2014, the Company was in compliance with all covenants for these Notes.

Term Loan Credit Agreement

Effective as of the Closing Date, the Company entered into a term loan credit agreement (the “Term Loan Credit Agreement”) which provides for a $350.0 million term loan facility (the “Term Loan”) with a single advance made on the Closing Date. The Term Loan was issued at a 2.5% discount and matures on December 16, 2020. Borrowings under the Term Loan will initially bear interest at one-month London Interbank Offered Rate (“LIBOR”) plus 6.50%. The interest rate at December 31, 2014 was 7.50%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the Term Loan.

The Term Loan Credit Agreement contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the Guaranty and Collateral Agreement, dated the Closing Date, the obligations under the Term Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2014, the Company was in compliance with all covenants for the Term Loan.

The Term Loan is guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries).

Add-on Term Loan

On January 22, 2015, the Company amended the Term Loan Credit Agreement to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the Term Loan Credit Agreement were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.

Revolving Credit Agreement

During the first quarter of 2014, the Company amended its existing revolving credit agreement to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, the Company further amended the revolving credit agreement, or the Second Amended and Restated Loan Agreement, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available in the U.S. and a $20.0 million sub-facility

102

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

available in Canada. The maximum principal amount available for borrowings under the credit agreement can be increased to $100.0 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce the balance available under the revolver. At December 31, 2014, availability on the revolver was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit. All extensions of credit under the revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the Company's subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the Term Loan have a subordinate lien on these assets. The revolver has a maturity date of December 31, 2018. The Company capitalized debt issuance costs of $0.7 million in 2014 related to the revolver amendments.

Borrowings under the Second Amended and Restated Loan Agreement initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Second Amended and Restated Loan Agreement) or at a rate 2.75% per annum in excess of LIBOR, at the Borrowers’ election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.

The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement include a fixed charge coverage ratio and an EBITDA measure. The fixed charge coverage ratio must meet or exceed a specified minimum. The EBITDA covenant requires a minimum amount of EBITDA to be achieved. The Company met these covenant requirements as of December 31, 2014.

10.75% Senior Notes

On February 7, 2014, the Company closed on a private offering of $425.0 million in aggregate principal amount of 10.75% senior notes due 2018 at a price of 106.875% plus accrued interest from February 1, 2014. The private offering had the same terms as the then existing $251.5 million outstanding 10.75% Senior Notes. Total proceeds of the offering were $454.2 million, which included $29.2 million of debt premium. The net proceeds of the offering of the $425.0 million private offering were used to finance the $282.8 million initial cash payment for the Canadian Acquisition and cash transaction costs associated with the Canadian Acquisition and the private offering of approximately $24.0 million. The remaining balance of the proceeds were used to fund the prepayment of the WML Notes and for other general corporate purposes. The Company recorded $12.5 million of loss on extinguishment of debt for the year ended December 31, 2014 related to the payoff of the WML term debt. This loss included an $11.6 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs. In connection with the WML prepayment, the WML revolving credit facility was terminated.

On December 16, 2014, the Company used the proceeds from the 8.75% Senior Secured Notes and the Term Loan to pay the $675.5 million aggregate outstanding balance of the 10.75% senior notes. In connection with the repayment of the 10.75 Senior Notes, the Company recorded loss on extinguishment of $34.9 million for the year ended December 31, 2014. This loss included an $32.9 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs and unamortized debt premium.

WMLP Loan

On December 31, 2014, WMLP closed on a new credit facility under a financing agreement (the “WMLP Loan”). The WMLP Loan consists of a $175.0 million term loan, with an option for an additional $120.0 million in term loans for acquisitions if requested by the WMLP and approved by the issuing lenders. The WMLP Loan matures in December 2018. Borrowings under the WMLP Loan are secured by substantially all of WMLP’s physical assets. Proceeds of the new credit facility were used to retire WMLP’s then existing first and second lien credit facilities and to pay fees and expenses related to its new credit facility, with the limited amount of remaining proceeds being available as working capital.

As of December 31, 2014, the $175.0 million outstanding under the WMLP Loan bears interest at a variable rate per annum equal to, at the WMLP’s option, the LIBOR (as defined in the WMLP Financing Agreement)(floor of 0.75% plus 8.50%) or the Reference Rate (as defined in the WMLP Financing Agreement). As of December 31, 2014, the WMLP Loan had a cash interest rate of 9.25%, consisting of the LIBOR floor (0.75%) plus 8.50%.

The WMLP Loan also provides for “PIK Interest” (paid-in-kind interest as defined in the WMLP Financing Agreement) at a variable rate per annum between 1.00% and 3.00% based on WMLP’s total net leverage ratio (as defined in the WMLP Financing Agreement). The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then outstanding principal amount of the term loan under the WMLP Loan. PIK Interest under the WMLP Loan was inconsequential for the year ended December 31, 2014.

103

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

As a result of WMLP refinancing the WMLP Loan, the Company recorded a $1.6 million loss on extinguishment of debt in the year ended December 31, 2014 as it pertains to cost associated with repayment of the existing outstanding debt held by WMLP.

The WMLP Loan contains customary financial and other covenants. As of December 31, 2014, WMLP was in compliance with all covenants under the terms of the WMLP Loan.

Capital Leases

The Company engages in leasing transactions for equipment utilized in its mining operations. At December 31, 2014 and 2013, the capital leases outstanding had a weighted average interest rate of 4.66% and 6.40%, respectively, and mature at various dates beginning in 2015 through 2020. During the year ended December 31, 2014, the Company entered into $15.6 million of new capital leases. In addition, we assumed $122.6 million of capital lease obligations in the Canadian Acquisition.

7. POSTRETIREMENT MEDICAL BENEFITS

The Company provides postretirement medical benefits to retired employees and their dependents, mandated by the Coal Industry Retiree Health Act of 1992 and pursuant to collective bargaining agreements. The Company also provides these benefits to qualified full-time employees pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.

The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:

	December 31,
	2014			2013
	(In thousands)
Change in benefit obligations:
Net benefit obligation at beginning of year	$	284,329		$	333,842
Service cost	3,289			4,436
Interest cost	12,814			12,139
Plan participant contributions	149			132
Actuarial loss (gain)	19,441			(53,230		)
Gross benefits paid	(14,860		)	(14,220		)
Federal subsidy on benefits paid	1,256			1,230
Net benefit obligation at end of year	306,418			284,329
Change in plan assets:
Employer contributions	14,711			14,088
Plan participant contributions	149			132
Gross benefits paid	(14,860		)	(14,220		)
Fair value of plan assets at end of year	—			—
Unfunded status at end of year	$	(306,418	)	$	(284,329	)
Amounts recognized in the balance sheet consist of:
Current liabilities	$	(13,263	)	$	(13,955	)
Noncurrent liabilities	(293,156		)	(270,374		)
Accumulated other comprehensive loss	39,716			20,292
Net amount recognized	$	(266,703	)	$	(264,037	)
Amounts recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	44,800		$	26,012
Prior service credit	(5,084		)	(5,720		)
	$	39,716		$	20,292

In 2014, the Company’s postretirement medical benefit liabilities increased $22.1 million. This increase was primarily driven by a $32.4 million increase due to decreases in discount rates and a $27.0 million increase due to updated mortality

104

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

tables. These increases were partially offset with a $39.9 million decrease in liability primarily due to improved claims experience.

The Company has elected to amortize its transition obligations over a 20-year period. Prior service costs and credits and actuarial gains and losses are amortized over the average life expectancy or average future service of the plan’s participants. The following amounts will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 (in millions):

Actuarial loss	$	1.9
Prior service credit	0.6

The components of net periodic postretirement medical benefit cost are as follows:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	3,289		$	4,436		$	3,555
Interest cost	12,814			12,139			12,363
Amortization of:
Transition obligation	—			—			93
Prior service credit	(635		)	(636		)	(636		)
Actuarial loss	653			4,641			3,116
Total net periodic benefit cost	$	16,121		$	20,580		$	18,491

The following table shows the net periodic postretirement medical benefit costs that relate to current and former mining operations:

	Years Ended December 31,
	2014		2013		2012
	(In thousands)
Former mining operations	$	9,614	$	12,475	$	11,314
Current operations	6,507		8,105		7,177
Total net periodic benefit cost	$	16,121	$	20,580	$	18,491

The costs for the former mining operations are included in Heritage health benefit expenses and the costs for current operations are included as operating expenses.

Assumptions

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2014	2013
Discount rate	3.75% - 4.25%	4.50% - 5.05%
Measurement date	December 31, 2014	December 31, 2013

The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.

The weighted-average assumptions used to determine net periodic benefit cost were as follows:

105

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	December 31,
	2014	2013	2012
Discount rate	4.50% - 5.05%	3.60% - 4.15%	4.10%
Measurement date	December 31, 2013	December 31, 2012	December 31, 2011

The following presents information about the assumed health care trend rate:

	December 31,
	2014		2013
Health care cost trend rate assumed for next year	6.50	%	6.75	%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	5.00	%	5.00	%
Year that the trend rate reaches the ultimate trend rate	2021		2021

The effect of a one percent change on the health care cost trend rate used to calculate periodic postretirement medical benefit costs and the related benefit obligation are summarized in the table below:

	Postretirement Medical Benefits
	1 % Increase		1 % Decrease
	(In thousands)
Effect on service and interest cost components	$	2,614	$	(2,096	)
Effect on postretirement medical benefit obligation	$	46,056	$	(37,003	)

Cash Flows

The following benefit payments and Medicare D subsidy (which the Company receives as a benefit partially offsetting its prescription drug costs for retirees and their dependents) are expected by the Company:

	Postretirement Medical  Benefits		Medicare D Subsidy			Net  Postretirement Medical Benefits
	(In thousands)
2015	$	13,263	$	(1,239	)	$	12,024
2016	13,572		(1,284		)	12,288
2017	13,889		(1,340		)	12,549
2018	14,299		(1,390		)	12,909
2019	14,663		(1,434		)	13,229
Years 2020 - 2024	76,900		(7,782		)	69,118

Combined Benefit Fund

Additionally, the Company makes payments to the UMWA Combined Benefit Fund, or CBF, which is a multiemployer health plan neither controlled by nor administered by the Company. The CBF is designed to pay health care benefits to UMWA workers (and dependents) who retired prior to 1976. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are based on the number of the Company’s UMWA employees who retired prior to 1976, and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. Contributions to the CBF have decreased over the past three years due to a declining population. The Company expenses payments to the CBF when they are due. The following payments were made to the CBF (in millions):

2014	$	2.0
2013	2.2
2012	2.3

Workers’ Compensation Benefits

106

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The Company was self-insured for workers’ compensation benefits prior to January 1, 1996. Since 1996, the Company has purchased third-party insurance for workers’ compensation claims.

The following table shows the changes in the Company’s workers’ compensation obligation:

	December 31,
	2014			2013
	(In thousands)
Workers’ compensation, beginning of year (including current portion)	$	7,461		$	9,530
Accretion	200			166
Claims paid	(405		)	(581		)
Actuarial changes	(270		)	(1,654		)
Workers’ compensation, end of year	6,986			7,461
Less current portion	(671		)	(717		)
Workers’ compensation, less current portion	$	6,315		$	6,744

The discount rates used in determining the workers’ compensation benefit accruals are adjusted annually based on ten-year Treasury bond rates. At December 31, 2014 and 2013, the rates were 2.0% and 3.0%, respectively.

Black Lung Benefits

The Company is self-insured for federal and state black lung benefits for former heritage employees and has established an independent trust to pay these benefits.

The following table sets forth the funded status of the Company’s black lung obligation:

	December 31,
	2014		2013
	(In thousands)
Actuarial present value of benefit obligation:
Expected claims from terminated employees	$	953	$	876
Amounts owed to existing claimants	13,054		13,267
Total present value of benefit obligation	14,007		14,143
Plan assets at fair value, primarily government-backed securities	2,755		5,468
Excess of the black lung benefit obligation over trust assets	$	11,252	$	8,675

The discount rates used in determining the actuarial present value of the black lung benefit obligation are based on corporate bond yields and are adjusted annually. At December 31, 2014 and 2013, the rates used were 3.40% and 4.00%, respectively.

Plan Assets

The fair value of the Company’s Black Lung trust assets by asset category is as follows:

	December 31, 2014
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs
	Fair Value		Level 1		Level 2
	(In thousands)
U.S. treasury securities	$	2,615	$	2,615	$	—
Cash and cash equivalents	140		140		—
	$	2,755	$	2,755	$	—

107

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	December 31, 2013
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs
	Fair Value		Level 1		Level 2
	(In thousands)
U.S. treasury securities	$	5,280	$	5,280	$	—
Mortgage-backed securities	185		—		185
Cash and cash equivalents	3		3		—
	$	5,468	$	5,283	$	185

The Black Lung Level 1 trust assets include cash and cash equivalents and U.S. treasury securities.

The Black Lung Level 2 trust assets include mortgage-backed securities which are valued via model using various inputs such as daily cash flow, snapshots of US Treasury market, floating rate indices as a benchmark yield, spread over index, periodic and life caps, next coupon adjustment date, and convertibility of the bond.

8. PENSION AND OTHER SAVING PLANS

Defined Benefit Pension Plans

The Company provides defined benefit pension plans to qualified full-time employees pursuant to collective bargaining agreements. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. The Company may make additional discretionary contributions. In 2009, the Company froze its pension plan for non-represented employees.

Supplemental Executive Retirement Plan

The Company maintains a Supplemental Executive Retirement Plan or SERP for former executives as a result of employment or severance agreements. The SERP is an unfunded non-qualified deferred compensation plan, which provides benefits to certain employees beyond the maximum limits imposed by the Employee Retirement Income Security Act and the Internal Revenue Code. The Company does not expect to add new participants to its SERP plan.

108

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The following table provides a reconciliation of the changes in the benefit obligations of the plans and the fair value of assets of the qualified plans and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP plans:

	Defined Benefit Pension December 31,						SERP December 31,
	2014			2013			2014			2013
	(In thousands)
Change in benefit obligation:
Net benefit obligation at beginning of year	$	155,075		$	172,289		$	3,640		$	4,241
Liability acquired	36,087			—			—			—
Service cost	2,425			2,346			—			—
Interest cost	7,963			6,209			168			152
Actuarial loss (gain)	32,505			(18,972		)	704			(359		)
Benefits and expenses paid	(15,119		)	(6,797		)	(383		)	(394		)
Settlements and curtailments	(10,862		)	—			—			—
Plan amendments	207			—			—			—
Foreign currency exchange rate changes	(1,315		)	—			—			—
Net benefit obligation at end of year	206,966			155,075			4,129			3,640
Change in plan assets:
Fair value of plan assets at the beginning of year	134,149			121,887			—			—
Assets acquired	36,616			—			—			—
Actual return on plan assets	14,392			18,414			—			—
Employer contributions	4,812			645			383			394
Benefits and expenses paid	(15,119		)	(6,797		)	(383		)	(394		)
Settlements	(12,795		)	—			—			—
Foreign currency exchange rate changes	(1,108		)	—			—			—
Fair value of plan assets at end of year	160,947			134,149			—			—
Unfunded status at end of year	$	(46,019	)	$	(20,926	)	$	(4,129	)	$	(3,640	)
Amounts recognized in the accompanying balance sheet consist of:
Current liability	$	—		$	—		$	(368	)	$	(390	)
Noncurrent liability	(46,019		)	(20,926		)	(3,760		)	(3,250		)
Accumulated other comprehensive loss	34,249			11,045			1,815			1,209
Net amount recognized at end of year	$	(11,770	)	$	(9,881	)	$	(2,313	)	$	(2,431	)
Amounts recognized in accumulated other comprehensive loss consist of:
Net actuarial loss	$	34,164		$	11,045		$	1,815		$	1,209
Prior service cost	85			—			—			—
	$	34,249		$	11,045		$	1,815		$	1,209

The accumulated benefit obligation for all plans was $211.1 million and $158.7 million at December 31, 2014 and 2013, respectively. The Company’s pension and SERP liabilities increased $25.6 million in 2014 primarily from decreases in discount rates, updated mortality tables, and the Canadian Acquisition.

Prior service costs and actuarial gains and losses are amortized over the expected future period of service of the plan’s participants. The following amounts will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 (in millions):

	Pension		SERP
Net actuarial loss	$	3.7	$	0.1

109

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The components of net periodic benefit cost are as follows:

	Defined Benefit Pension Years Ended December 31,									SERP Years Ended December 31,
	2014			2013			2012			2014		2013		2012
	(In thousands)
Components of net periodic benefit cost:
Service cost	$	2,425		$	2,346		$	2,139		$	—	$	—	$	—
Interest cost	7,963			6,209			6,330			168		152		172
Expected return on plan assets	(10,796		)	(8,770		)	(8,241		)			—		—
Settlements and curtailments	4,585			—			—			—		—		—
Amortization of:
Prior service cost	—			—			—			—		—		—
Actuarial loss	1,217			3,377			2,867			97		112		95
Total net periodic pension cost	$	5,394		$	3,162		$	3,095		$	265	$	264	$	267

These costs are included in the accompanying statements of operations in Cost of sales and Selling and administrative expenses.

In certain of the Company's pension plans, lump sum distributions during 2014 exceeded the sum of those plans' service and interest costs. As a result, the Company recorded a $3.7 million loss on settlement accounting in 2014. In addition, the Company recorded a $0.9 million loss on curtailment accounting due to the expectation that the future service of present employees at the Beulah Mine will be significantly reduced in the future. These costs are included in the accompanying statements of operations in Selling and administrative expenses.

Assumptions

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	Defined Benefit Pension December 31,		SERP December 31,
	2014	2013	2014	2013
Discount rate	3.60% - 3.90%	4.25% - 4.65%	3.90%	4.65%
Measurement date	December 31, 2014	December 31, 2013	December 31, 2014	December 31, 2013

The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.

The following table provides the assumptions used to determine net periodic benefit cost:

	Defined Benefit Pension Years Ended December 31,			SERP Years Ended December 31,
	2014	2013	2012	2014	2013	2012
Discount rate	4.25% - 4.70%	3.35% - 3.75%	4.05% - 4.25%	4.65%	3.75%	4.25%
Expected return on plan assets	7.40%	7.40%	7.40%	N/A	N/A	N/A
Rate of compensation increase	N/A	N/A	N/A	N/A	N/A	N/A
Measurement date	December 31, 2013	December 31, 2012	December 31, 2011	December 31, 2013	December 31, 2012	December 31, 2011

The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Company utilizes modern portfolio theory modeling techniques in the development of its return assumptions. This technique projects rates of return that can be generated through various asset allocations that lie within the risk tolerance set forth the Company. The risk assessment provides a link

110

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

between a pension plan's risk capacity, management's willingness to accept investment risk and the asset allocation process, which ultimately leads to the return generated by the invested assets.

Plan Assets

The Company’s investment goals are to maximize returns subject to specific risk management policies. The Company sets the expected return on plan assets based on historical trends and forecasts provided by its third-party fund managers. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company invested in its common stock in 2011 in order to meet plan funding requirements. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in fixed income and equity securities, both domestic and international. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.

The weighted-average target asset allocation of the Company’s pension trusts were as follows at December 31, 2014:

	Target Allocation
Asset category
Cash and equivalents	0% - 10%
Equity securities funds	20% - 60%
Debt securities funds	40% - 80%
Other	0% - 10%

The fair value of the Company’s pension plan assets by asset category is as follows:

	December 31, 2014
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	Fair Value		Level 1		Level 2		Level 3
	(In thousands)
Pooled separate accounts:
Large-cap blend (a)	$	47,092	$	—	$	47,092	$	—
International blend (b)	7,290		—		7,290		—
Fixed income domestic (c)	23,057		—		23,057		—
Fixed income long term (d)	47,299		—		47,299		—
Stable value (e)	5,346		—		5,346		—
Registered investment companies – growth fund	16,490		16,490		—		—
Limited partnerships and limited liability companies	224		—		—		224
Westmoreland Coal common stock	1,539		1,539		—		—
Cash and cash equivalents	12,610		12,610		—		—
	$	160,947	$	30,639	$	130,084	$	224

111

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	December 31, 2013
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	Fair Value		Level 1		Level 2		Level 3
	(In thousands)
Pooled separate accounts:
Large-cap blend (a)	$	48,983	$	—	$	48,983	$	—
International blend (b)	18,191		—		18,191		—
Fixed income domestic (c)	40,944		—		40,944		—
Fixed income long term (d)	17,797		—		17,797		—
Stable value (e)	5,267		—		5,267		—
Limited partnerships and limited liability companies	250		—		—		250
Westmoreland Coal common stock	2,255		2,255		—		—
Cash and cash equivalents	462		462		—		—
	$	134,149	$	2,717	$	131,182	$	250

(a) Large-cap blend funds seek to provide long-term growth of capital. They seek to provide investment results that approximate the performance of the Standard & Poor’s Composite 1500 Index.

(b) International blends seek to have a diversified portfolio of investments, invading fixed-income and equity-focused investments in international markets.

(c) Fixed income domestic funds seek to invest in high-quality corporate bonds with over 15 years to maturity.

(d) Fixed income long term bond funds seek to achieve performance results similar to the Barclays Capital U.S. Aggregate Bond Index. This fund invests primarily in corporate and government bonds.

(e) The stable value fund seeks to invest in publicly traded and privately placed debt securities and mortgage loans, and to a lesser extent, real estate and other equity investments in order to provide a guaranteed rate of return.

The Company’s Level 1 assets include securities held by registered investment companies and its common stock, which are both typically valued using quoted market prices of an active market. Cash and cash equivalents and short-term investments are predominantly held in money market accounts.

The Company’s Level 2 assets include pooled separate accounts, which are valued based on the quoted market prices of the securities underlying the investments.

The Company’s Level 3 assets include interest in limited partnerships and limited liability companies that invest in privately held companies or privately held real estate assets. These assets are valued by the respective partnership or company manager using market and income approaches. The market approach consists of using comparable market transactions or values. The income approach consists of the net present value of estimated future cash flows, adjusted as appropriate for liquidity, credit, market and other risk factors. The inputs considered in the valuations include original transaction prices, recent transactions in the same or similar instruments, changes in financial ratios or cash flows, discounted cash flow valuations, and general economic and market conditions.

A summary of changes in the fair value of the Plan’s Level 3 assets is shown below:

112

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	Limited partnerships and limited liability companies
	Year Ended December 31,
	2014			2013
	(In thousands)
Beginning balance	$	250		$	614
Unrealized gain	19			5
Settlements, net	(45		)	(369		)
Ending balance	$	224		$	250

Contributions

The Company contributed $4.8 million to its retirement plans during 2014. Of these contributions, $2.9 million was made in cash and $1.9 million was made in Company stock. In 2015, the Company expects to make approximately $1.2 million of pension plan contributions.

Cash Flows

The following benefit payments are expected to be paid from its pension plan assets:

	Pension Benefits
	(In thousands)
2015	$	8,195
2016	12,255
2017	9,235
2018	9,569
2019	10,089
Years 2020 - 2024	56,107

The benefits expected to be paid are based on the same assumptions used to measure the Company’s pension benefit obligation at December 31, 2014 and include estimated future employee service.

Multi-Employer Pension

The Company contributes to the Central Pension Fund, or the Plan, a multiemployer defined benefit pension plan for its WECO, WRI and WSC entities pursuant to collective bargaining agreements. The Plan’s Employer Identification Number is 36-6052390. These employers contribute to the Plan based on a negotiated rate per hour worked per participating employee. For the Plan’s year-end dates of January 31, 2014 and 2013, no single employer contributed more than 5% of total contributions to the Plan. As of the Plan’s year-end date January 31, 2014, it had a healthy or greater than 80% funding status.

The following table shows required information for each employer contributing to the Central Pension Fund:

	WECO		WRI		WSC
Employer plan number	9313		9243		4990
Minimum contributions per hour worked	$5.80 - $5.85		$	5.70	$3.45 - $4.70
Expiration date of collective bargaining agreements	2/28/2019		5/31/2015		4/1/2016
Employer contributions (in millions):
2014	$	3.3	$	1.2	$	0.1
2013	3.4		0.9		0.1
2012	3.2		0.5		0.1

Other Plans

The Company sponsors 401(k) saving plans for U.S. employees and provides contributions to employee savings plans at its Canadian operation to assist employees in providing for their future retirement needs. The Company’s expense was $8.5 million, $3.6 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. During 2014, the

113

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Company’s expense of $8.5 million consisted of $6.7 million in cash contributions and $1.8 million in contributions of Company stock to the plans. During 2013, the Company’s expense of $3.6 million consisted of $1.2 million in cash contributions and $2.4 million in contributions of Company stock to the plans. During 2012, the Company’s expense was all from contributions of Company stock to the plans.

9. HERITAGE HEALTH BENEFIT EXPENSES

The caption Heritage health benefit expenses used in the consolidated statements of operations refers to costs of benefits the Company provides to its former mining operation employees. The components of these expenses are as follows:

	Years Ended December 31,
	2014		2013			2012
	(In thousands)
Health care benefits	$	9,473	$	12,579		$	11,367
Combined benefit fund payments	1,966		2,240			2,258
Workers’ compensation benefits (credit)	230		(1,212		)	(1,322		)
Black lung benefits (credit)	1,719		(189		)	1,085
Total	$	13,388	$	13,418		$	13,388

10. ASSET RETIREMENT OBLIGATIONS, CONTRACTUAL THIRD-PARTY RECLAMATION RECEIVABLE, AND RECLAMATION DEPOSITS

The asset retirement obligation, contractual third-party reclamation receivable, and reclamation deposits for the Company at December 31, 2014 are summarized below:

	Asset Retirement Obligation		Contractual Third-Party Reclamation Receivable		Reclamation Deposits
	(In thousands)
Coal - U.S.	$	291,964	$	110,006	$	77,907
Coal - Canada	128,135		6,477		—
Coal - WMLP	31,685		—		—
Power	961		—		—
Total	$	452,745	$	116,483	$	77,907

Asset Retirement Obligations

Changes in the Company’s asset retirement obligations were as follows:

	Years Ended December 31,
	2014			2013
	(In thousands)
Asset retirement obligations, beginning of year (including current portion)	$	279,864		$	263,847
Accretion	31,033			21,905
Liabilities settled	(23,935		)	(21,630		)
Changes due to amount and timing of reclamation	10,042			15,742
Asset retirement obligations acquired	162,394			—
Changes due to foreign currency translation	(6,653		)	—
Asset retirement obligations, end of year	452,745			279,864
Less current portion	(43,289		)	(23,353		)
Asset retirement obligations, less current portion	$	409,456		$	256,511

114

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

As permittee, the Company or its subsidiaries are responsible for the total amount of final reclamation costs for its mines and ROVA. The financial responsibility for a portion of final reclamation of the mines when they are closed has been transferred by contract to certain customers, while other customers have provided guarantees or funded escrow accounts to cover final reclamation costs. Costs of reclamation of mining pits prior to mine closure are recovered in the price of coal shipped.

As of December 31, 2014, the Company had $353.7 million in surety bonds outstanding and $107.8 million in letters of credit to secure reclamation obligations.

Contractual Third-Party Reclamation Receivables

The Company has recognized as an asset of $116.5 million as contractual third-party reclamation receivables, representing the present value of customer obligations to reimburse the Company for reclamation expenditures at the Company’s Rosebud, Jewett and Absaloka Mines.

Reclamation Deposits

The Company’s reclamation deposits will be used to fund final reclamation activities. The Company’s carrying value and estimated fair value of its reclamation deposits at December 31, 2014 are as follows:

	Carrying Value		Fair Value
	(In thousands)
Cash and cash equivalents	$	44,519	$	44,519
Available-for-sale securities	33,388		33,388
	$	77,907	$	77,907

In 2014, the Company recorded a gain of less than $0.1 million on the sale of available-for-sale securities held as reclamation deposits.

The cost basis of an investment sold is specifically identified.

Held-to-Maturity and Available-for-Sale Reclamation Deposits

The amortized cost, gross unrealized holding gains and losses and fair value of held-to-maturity securities are as follows:

	December 31,
	2014		2013
	(In thousands)
Amortized cost	$	—	$	11,396
Gross unrealized holding gains	—		764
Gross unrealized holding losses	—		(74		)
Fair value	$	—	$	12,086

The cost basis, gross unrealized holding gains and fair value of available-for-sale securities are as follows:

	December 31,
	2014			2013
	(In thousands)
Cost basis	$	32,930		$	—
Gross unrealized holding gains	886			—
Gross unrealized holding losses	(428		)	—
Fair value	$	33,388		$	—

Maturities of available-for-sale securities are as follows at December 31, 2014:

115

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	Cost		Fair Value
	(In thousands)
Within one year	$	452	$	475
Due in five years or less	17,142		17,282
Due after five years to ten years	7,142		7,183
Due in more than ten years	8,194		8,448
	$	32,930	$	33,388

11. DERIVATIVE INSTRUMENTS

Derivative Liabilities

The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception, or contain features that qualify as embedded derivatives. All derivative financial instruments, except for derivatives that qualify for the normal purchase normal sale exception, are recognized on the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or in other comprehensive income if they qualify for cash flow hedge accounting.

In the first quarter of 2014, the Company entered into two foreign currency exchange forward contracts to purchase Canadian Dollars to manage a portion of its exposure to fluctuating rates of exchange on anticipated Canadian Dollar-denominated Canadian Acquisition cash flows. These two foreign currency contracts had a total notional amount of $348.3 million and were settled in April 2014.

During 2014, the Company entered into contracts to purchase power at its ROVA facility to manage exposure to power price fluctuations. These contracts cover the period from April 2014 to March 2019 and contracted power prices range from $41.05 to $56.33 megawatts per hour, with a weighted average contract price of $43.71 over the remaining contract lives. The fair value of these power price derivatives are based on comparing contracted prices to projected future prices.

The fair value of outstanding derivative instruments not designated as hedging instruments on the accompanying Consolidated Balance Sheet was as follows (in thousands):

Derivative Instruments	Balance Sheet Location	December 31, 2014
Contracts to purchase power	Other current liabilities	$	8,265
Contracts to purchase power	Other liabilities	21,103

The effect of derivative instruments not designated as hedging instruments on the accompanying Consolidated Statements of Operations was as follows (in thousands):

		Year Ended December 31,
Derivative Instruments	Statement of Operations Location	2014			2013		2012
Canadian dollar foreign exchange contracts	Loss on foreign exchange	$	(6,209	)	$	—	$	—
Contracts to purchase power	Derivative loss	(31,100		)	—		—

12. FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company is required to disclose the fair value of financial instruments where practicable. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the consolidated balance sheets approximate the fair value of these instruments due to the short duration to their maturities. Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available (Level 2) and otherwise using discount rate estimates based on interest rates as of December 31, 2014 (Level 3).

The estimated fair value of the Company’s debt with fixed and variable interest rates are as follows:

116

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

	Fixed Interest Rate				Variable Interest Rate
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)				(In thousands)
December 31, 2013	$	328,473	$	364,329	$	—	$	—
December 31, 2014	$	345,498	$	348,250	$	341,300	$	344,750

The table below sets forth, by level, the Company’s financial assets and liabilities that are accounted for at fair value on a recurring basis:

	Balance at December 31, 2014
				Quoted Prices in Active Markets for Identical Assets or Liabilities		Significant Other Observable Inputs
	Fair Value			Level 1		Level 2
	(In thousands)
Assets:
Available-for-sale investments included in Restricted investments and bond collateral	$	34,057		$	34,057	$	—
Available-for-sale investments included in Reclamation deposits	33,388			33,388		—
	$	67,445		$	67,445	$	—
Liabilities:
Contracts to purchase power included in Other current liabilities and Other liabilities	$	(29,368	)	$	—	$	(29,368	)
Warrants issued by WMLP included in Other liabilities	(1,981		)	—		(1,981		)
	$	(31,349	)	$	—	$	(31,349	)

13. RESTRICTED STOCK UNITS, STOCK OPTIONS, AND STOCK APPRECIATION RIGHTS (SARs)

As of December 31, 2014, the Company had restricted stock units, stock options, and stock-settled stock appreciation rights, or SARs, outstanding from three stock incentive plans. Two of these plans were terminated in October 2009. The Company grants employees and non-employee directors restricted stock units from the Amended and Restated 2007 and 2014 Equity Incentive Stock Plans. The Company grants employees and non-employee directors restricted stock units. Non-employee directors receive equity awards with a value of $90,000 after each annual meeting.

The maximum number of remaining shares that can be issued under the 2007 Incentive Stock Plan is 60,709. The maximum number of remaining shares that can be issued under the 2014 Incentive Stock Plan is 404,706.

Compensation cost arising from share-based arrangements is shown in the following table:

	Years Ended December 31,
	2014		2013		2012
	(In thousands)
Recognition of fair value of restricted stock units, stock options and SARs over vesting period; and issuance of stock	$	4,318	$	2,967	$	3,088
Contributions of stock to the Company’s 401(k) plan	1,764		2,355		2,952
Total share-based compensation expense	$	6,082	$	5,322	$	6,040

Restricted Stock Units

The Company may issue restricted stock units, which requires no payment from the employee. Restricted stock units typically vest ratably over three years. Upon vesting, the Company can elect to settle the restricted stock units in either cash or the Company’s common stock. Compensation expense is based on the fair value on the grant date and is recorded ratably over the vesting period.

117

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

In June 2014, the Company granted 142,444 restricted stock units, of which 71,244 units will vest ratably over a three-year period. The remaining 71,200 units are performance based, which will vest and pay out at the end of a three-year period if performance goals are met. The Company’s management believes it is probable that the target performance condition will be met.

A summary of restricted stock award activity for the year ended December 31, 2014 is as follows:

	Units		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense (In thousands)
Non-vested at December 31, 2013	587,975		$	9.46
Granted	178,783		$	30.67
Vested	(264,965	)	$	13.38
Forfeited	(92,431	)	$	15.11
Non-vested at December 31, 2014	409,362		$	13.87	$	3,207	(1)

____________________ 

(1) Expected to be recognized over the next three years.

Additional information related to restricted stock units:

Years Ended December 31:	Weighted Average Grant-Date Fair Value		Total Grant- Date Fair Value of Restricted Stock Units that Vested (In thousands)
2014	$	30.67	$	3,536
2013	$	11.70	$	1,689
2012	$	7.57	$	1,336

Stock Options

Stock options generally vest over three years, expire ten years from the date of grant, and have an option price equal to the market value of the stock on the date of grant.

Information with respect to stock option activity for the year ended December 31, 2014, is as follows:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (In years)	Aggregate Intrinsic Value (In thousands)		Unamortized Compensation Expense (In thousands)
Outstanding at December 31, 2013	145,806		$	21.97
Exercised	(35,000	)	$	21.40
Expired	—		$	—
Outstanding and exercisable at December 31, 2014	110,806		$	22.15	3.178	$	—	$	—

Additional information related to stock options:

Years Ended December 31:	Intrinsic Value of Stock Options Exercised
2014	$	11.81
2013	$	—
2012	$	—

There were no stock options granted during 2014, 2013 or 2012.

118

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

SARs

SARs generally vest over three years, expire ten years from the date of grant, and have a base price equal to the market value of the stock on the date of grant. Upon vesting, the holders may exercise the SARs and receive a number of shares of common stock having a value equal to the appreciation in the value of the common stock between the grant date and the exercise date.

Information with respect to SARs granted and outstanding for the year ended December 31, 2014 is as follows:

	SARs		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (In years)	Aggregate Intrinsic Value (In thousands)		Unamortized Compensation Expense (In thousands)
Outstanding at December 31, 2013	70,734		$	22.60
Exercised	(53,791	)	$	21.71
Expired	—		$	—
Outstanding and exercisable at December 31, 2014	16,943		$	25.44	1.4	$	—	$	—

Additional information related to SARs:

Years Ended December 31:	Intrinsic Value of SARs Exercised
2014	$	11.50
2013	$	—
2012	$	—

There were no SARs granted during 2014, 2013, or 2012.

No SARs vested during 2012, 2013, or 2014.

14. STOCKHOLDERS’ EQUITY AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Preferred and Common Stock

The Company has two classes of capital stock outstanding, common stock, par value $2.50 per share, and Series A Convertible Exchangeable Preferred Stock on which cumulative dividends of $2.125 per share are payable quarterly. Each share of Series A Preferred Stock is represented by four Depositary Shares. Under the terms of the Series A Preferred Stock, the Company can redeem preferred shares at any time for the redemption value of $100.00 plus any accumulated dividends paid in cash. The Company is permitted to pay preferred stock dividends to the extent there is a surplus, defined by Delaware law. During the year ended December 31, 2014, approximately 68,291 shares of preferred stock were converted into 466,537 shares of common stock. Subsequent to December 31, 2014, approximately 88,369 shares of preferred stock were converted into 603,713 shares of common stock and 3,175 shares of preferred stock were redeemed under a mandatory redemption for $0.3 million. The Company paid $0.9 million of preferred stock dividends for the year ended December 31, 2014.

119

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Accumulated Other Comprehensive Income (Loss)

The following is a summary of accumulated other comprehensive income (loss):

	Pension and Postretirement Medical Benefits			Available for Sale Securities			Foreign currency translation adjustment			Tax Effect of Other Comprehensive Income Gains			Accumulated Other Comprehensive Loss
	(In thousands)
Balance at January 1, 2012	$	(95,624	)	$	325		$	—		$	(26,156	)	$	(121,455	)
2012 activity	(26,622		)	(268		)	—			—			(26,890		)
Balance at December 31, 2012	(122,246		)	57			—			(26,156		)	(148,345		)
2013 activity	89,699			(57		)	—			(4,892		)	84,750
Balance at December 31, 2013	(32,547		)	—			—			(31,048		)	(63,595		)
2014 activity	(43,234		)	413			(17,880		)	—			(60,701		)
Balance at December 31, 2014	$	(75,781	)	$	413		$	(17,880	)	$	(31,048	)	$	(124,296	)

Pension and postretirement medical benefit adjustments relate to changes in the funded status of various benefit plans. The unrealized gains and losses associated with recognizing the Company’s “available-for-sale” securities at fair value are recorded through Accumulated other comprehensive loss.

Changes in Accumulated Other Comprehensive Income

The following table reflects the changes in accumulated other comprehensive income (loss) by component:

	Pension			Postretirement medical benefits			Available for sale securities		Foreign currency translation adjustment			Tax effect of other comprehensive income gains			Accumulated other comprehensive loss
	(In thousands)
Balance at December 31, 2013	$	(12,255	)	$	(20,292	)	$	—	$	—		$	(31,048	)	$	(63,595	)
Other comprehensive income before reclassifications	(24,793		)	(19,442		)	144		(17,880		)	—			(61,971		)
Amounts reclassified from accumulated other comprehensive income (loss)	983			18			269		—			—			1,270
Balance at December 31, 2014	$	(36,065	)	$	(39,716	)	$	413	$	(17,880	)	$	(31,048	)	$	(124,296	)

The following table reflects the reclassifications out of accumulated other comprehensive income (loss) for the year ended December 31, 2014 (in thousands):

120

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Details about accumulated other comprehensive income (loss) components	Amount reclassified from accumulated other comprehensive income (loss)(1)			Affected line item in the statement where net income (loss) is presented
Available-for sale securities
Realized gains and losses on available-for sale securities	$	269		Other income (loss)
	$	269		Total
Amortization of defined benefit pension items:
Actuarial losses	$	983		(2)
Amortization of postretirement medical items:
Prior service costs	$	(635	)	(3)
Actuarial losses	653			(3)
	$	18		Total

____________________

(1) Amounts in parentheses indicate debits to income/loss.

(2) These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 8 - Pension and Other Savings Plans for additional details)

(3) These accumulated other comprehensive income components are included in the computation of net periodic postretirement medical cost. (See Note 7 - Postretirement Medical Benefits for additional details)

Restricted Net Assets

WCC has obligations to pay pension and postretirement medical benefits, to fund corporate expenditures, and to pay interest on the 8.75% Senior Secured notes and the Term Loan Facility due 2020. However, WCC conducts no operations, has no source of revenue and is fully dependent on distributions from its subsidiaries to pay its costs. Due to the Master Limited Partnership structure and the WMLP Term Loan Facility due 2018, at December 31, 2014, WMLP is limited in its ability to distribute funds to WCC. The amount of cash WMLP can distribute on its units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter. WMLP's Term Loan Facility contains customary financial and other covenants and it permits distributions to its unitholders under specified circumstances. Borrowings under the WMLP Term Loan Facility are secured by substantially all of its physical assets.

At December 31, 2014, WMLP had approximately $73.0 million of net assets that were not available to be transferred to WCC in the form of dividends, loans, or advances due to restrictions on the Master Limited Partnership as mentioned above.

Equity Offering

On July 16, 2014, the Company completed a public offering of 1,684,507 shares of common stock at $35.50 per share for gross proceeds of $59.8 million. Brokerage fees were $1.775 per share or $3.0 million and legal and other fees associated with the offering were $0.3 million.

121

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

15. INCOME TAX

The Company’s loss before income taxes is as follows:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
U.S.	$	(157,043	)	$	(12,909	)	$	(13,572	)
Foreign	(15,905		)	—			—
	$	(172,948	)	$	(12,909	)	$	(13,572	)

Income tax expense (benefit) attributable to net loss before income taxes consists of:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Current:
Federal	$	—		$	(2	)	$	(8	)
State	120			112			98
Foreign	545			—			—
	665			110			90
Deferred:
Federal	—			(4,189		)	—
State	—			(703		)	—
Foreign	(433		)	—			—
	(433		)	(4,892		)	—
Income tax expense (benefit)	$	232		$	(4,782	)	$	90

Income tax expense (benefit) attributable to net loss before income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate of 34% to pre-tax loss as a result of the following:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Computed tax benefit at U.S. statutory rate	$	(58,066	)	$	(4,389	)	$	(4,615	)
Increase (decrease) in tax expense resulting from:
Tax depletion in excess of basis	(9,273		)	(6,187		)	(4,782		)
Non-deductible acquisition costs	2,979			—			—
Non-deductible interest expense	(4,174		)	1,167			2,188
State income taxes, net	(9,321		)	(2,506		)	(3,427		)
Change in valuation allowance	77,771			15			8,571
Indian Coal Tax Credits	(15,205		)	92			83
Federal and state NOL expiration	—			—			153
State rate differential	(385		)	6,202			2,049
Foreign income inclusion	18,608			—			—
Foreign permanent expenses and other	413			—			—
Foreign tax rate differential	1,383			—			—
Reversal of Canadian uncertain tax position	(5,575		)	—			—
Other, net	1,077			824			(130		)
Income tax expense (benefit)	$	232		$	(4,782	)	$	90

122

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The increase in valuation allowance for the year ended December 31, 2014 is due to the tax effect of the change in current year temporary items, credits, net operating losses, and postretirement medical benefit and pension obligations.

For the year ended December 31, 2013, the Company recorded a tax benefit of approximately $4.9 million due to non-cash income tax expense related to gains recorded within other comprehensive income during 2013. Generally accepted accounting principles, or GAAP, requires all items be considered, including items recorded in other comprehensive income, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with GAAP, the Company recorded a tax benefit on its loss from continuing operations, which was exactly offset by income tax expense on other comprehensive income as follows:

	Loss From Continuing Operations			Other Comprehensive Income			Total Comprehensive Income
	(In thousands)
Pre-allocation	$	110		$	—		$	110
Tax allocation	(4,892		)	4,892			—
As presented	$	(4,782	)	$	4,892		$	110
Components of OCI gain:
	Gross			Tax Allocation
Pension	$	32,464		$	1,772
Post-retirement benefits	57,235			3,123
Unrealized gain (loss) on securities	(57		)	(3		)
Total	$	89,642		$	4,892

The PPACA reduces the tax benefits available to an employer that receives the Medicare Part D subsidy beginning in years ending after December 31, 2010. As a result of the PPACA, employers that receive the Medicare Part D subsidy will recognize the deferred tax effects of the reduced deductibility of the postretirement prescription drug coverage in the period the PPACA was enacted. On March 30, 2010, a companion bill, the Reconciliation Act, was signed into law. The Reconciliation Act reduces the effect of the PPACA on affected employers by deferring for two years (until years ending after December 31, 2012) the reduced deductibility of the postretirement prescription drug coverage. Accounting for income taxes requires that the effect of adjusting the deferred tax asset for the elimination of this deduction be included in income from continuing operations. However, entities that have a full valuation allowance for this deferred tax asset would recognize a related decrease in the valuation allowance. As the Company has a full valuation allowance against its related deferred tax asset, this change in tax law regarding the Medicare Part D subsidy will not have an effect on the Company’s income from continuing operations.

On September 13, 2013, the IRS issued T.D. 9636, Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property (the “Repairs Regulations”) under Internal Revenue Code (“IRC”) Sections 162(a) and 263(a) with an effective date of January 1, 2014. These Repair Regulations address the timing of when costs incurred to acquire, produce or improve tangible property must be capitalized or may be deducted as incurred. Additional guidance was provided in Rev Proc 2014-16 on January 24, 2014; Final regulations regarding the dispositions of depreciable property was issued in August 2014 and procedures to adopt the disposition regulations was issued in September 2014  The analysis of the Repair Regulations resulted in a benefit of approximately $4.7 million, netted with plant, property and equipment.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below:

	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Federal net operating loss carryforwards	$	105,464		$	89,698
State net operating loss carryforwards	32,961			26,509
Foreign net operating loss carryforwards	27,893			—
Investment in WMLP	1,185			—
Alternative minimum tax credit carryforwards	7,168			7,179
Charitable contribution carryforwards	171			146
Indian Coal Tax Credit carryforwards	40,704			25,499
Accruals for the following:
Workers’ compensation	2,592			2,726
Postretirement medical benefit and pension obligations	124,854			106,912
Incentive plans	1,969			1,606
Asset retirement obligations	101,514			68,989
Deferred revenues	15,841			18,919
Excess of pneumoconiosis benefit obligation over trust assets	4,244			3,262
Acquisition costs	212			1,276
Restructuring	4,797			1,909
Unrealized gain/(loss) on derivatives	11,078			—
Canadian resource pool	6,435			—
Lease obligations	23,401			—
Depreciable capital assets	6,779			—
Other accruals	6,536			6,656
Total gross deferred assets	525,798			361,286
Less valuation allowance	(406,143		)	(264,464		)
Net deferred tax assets	119,655			96,822
Deferred tax liabilities:
Property, plant and equipment, differences due to depreciation and amortization	(113,430		)	(94,868		)
Investment in Joint Venture	(7,324		)	—
Finance lease receivable	(15,232		)	—
Deferred reclamation revenue	(1,688		)	—
Other	(3,750		)	(1,954		)
Total gross deferred tax liabilities	(141,424		)	(96,822		)
Net deferred tax liability	$	(21,769	)	$	—

The net valuation allowance increased by $141.7 million during the year ended December 31, 2014 and decreased by $29.0 million during the year ended December 31, 2013.

As of December 31, 2014, the Company had significant deferred tax assets. The deferred tax assets include U.S. federal, state regular and foreign NOLs, AMT credit carryforwards, ICTC carryforwards, charitable contribution carryforwards, and net deductible reversing temporary differences related to on-going differences between book and taxable income.

In the U.S. jurisdiction, the Company believes it will be taxed under the AMT system for the foreseeable future due to the significant amount of statutory tax depletion in excess of book depletion expected to be generated by its mining operations. As a result, Westmoreland has determined that a valuation allowance is required for all of its regular federal net operating loss carryforwards and AMT credit carryforwards, since they are only available to offset future regular taxes. As of December 31, 2014, the Company has an estimated $7.2 million of AMT credit carryforwards, which have an indefinite carryover life, with no expiration.

As of December 31, 2014, the Company has an estimated $40.7 million in ICTC carryforwards that are available to offset the Company's regular tax and AMT liabilities. The Company has determined that a full valuation allowance is required for all its ICTC carryforward. The ICTC can generally be used to offset AMT liability. The Company does not believe it has sufficient positive evidence of significant magnitude to substantiate that its deferred tax asset for the ICTC carryforward is realizable at a more-likely-than-not level of assurance. As a result, the Company will continue to record a full valuation allowance on its ICTC carryforward; reversing valuation allowance only if utilized in a future year. ICTC credits are a general business credit with a 20-year carryforward period. The majority of the credits will expire in years 2021-2034.

The Company has determined that since its net deductible temporary differences will not reverse for the foreseeable future, and it is unable to forecast that it will have regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets.

As of December 31, 2014, the Company has available U.S. federal net operating loss carryforwards to reduce future regular taxable income, which expire as follows:

Expiration Date	Regular Tax
	(In thousands)
2018	$	28
2019	88,429
2020	32
2021	20
after 2022	226,463
Total	$	314,972

As of December 31, 2014, the Company also has an estimated $901 million in state net operating loss carryforwards, expiring in years 2016 through 2034, to reduce future taxable income. The Company has recorded a full valuation allowance for all of its state net operating losses since it believes they will not be realized in the foreseeable future. A portion of the Company's deferred tax assets include NOL benefits that if realized would result in an increase to other paid-in capital.

The Company files tax returns in the U.S. federal jurisdiction and in various U.S. state jurisdictions, and is subject to examination by taxing authorities in all of these jurisdictions. From time to time, the Company's tax returns are reviewed or audited by various U.S. federal and state taxing authorities. The Company believes that adjustments, if any, resulting from these reviews or audits would not be material, individually or in the aggregate, to the Company's financial position, results of operations or liquidity. It is reasonably possible that the amount of unrecognized tax benefits related to certain of the Company's tax positions will increase or decrease in the next twelve months as audits or reviews are initiated and settled. At this time, an estimate of the range of a reasonably possible change cannot be made. With few exceptions, the Company is not subject to income tax examinations by U.S. federal or state jurisdictions for fiscal years prior to 2011.

Currently the Company has an excess tax over book basis in its investment in Canadian subsidiaries and the Company does not expect this deferred tax asset to reverse in the foreseeable future. Accordingly, there has been no recognition of any deferred tax asset on the outside basis of investments in subsidiaries, in accordance with ASC 740.

Foreign Income Taxes

As of December 31, 2014, the Company has available Canadian net operating loss carryforwards to reduce future regular taxable income, which expire as follows:

Expiration Date	Canadian Tax
	(In thousands)
2018	$	—
2019	—
2020	—
2021	—
after 2022	104,324
Total	$	104,324

As of December 31, 2014, the Company also has available an estimated $76 million in provincial net operating loss carryforwards, expiring in years 2023 through 2033 to reduce future taxable income.

The Company has significant Canadian and provincial deferred tax assets including net operating losses, AROs, lease obligations, and depreciable assets.

With respect to one of its Canadian entities, the Company has determined that since it has significant net operating losses, its net deductible temporary differences will not reverse for the foreseeable future, and it is unable to forecast that it will have regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets.

The Company files tax returns in the Canadian jurisdiction and in various Canadian provincial jurisdictions, and is subject to examination by taxing authorities in these jurisdictions. From time to time, the Company's tax returns are reviewed or audited by the various taxing authorities. The Company believes that an adjustment made by a Canadian taxing authority, if any, resulting from these reviews or audits would not be material, individually or in the aggregate, to the Company's financial position, results of operations or liquidity. It is reasonably possible that the amount of unrecognized tax benefits related to certain of the Company's tax positions will increase or decrease in the next twelve months as audits or reviews are initiated and settled. At this time, an estimate of the range of a reasonably possible change cannot be made. With few exceptions, the Company is not subject to income tax examinations by Canadian and provincial jurisdictions for fiscal years prior to 2013.

Uncertain tax positions

For the year ended December 31, 2014, Westmoreland had no long-term liability related to U.S. or foreign uncertain tax positions. The Canadian taxing authorities have completed their review related to the utilization of prior losses, with no change. The Company has elected under ASC 740-10-40 to recognize interest and penalties related to income tax matters in income tax expense, for which none was recorded for the years ended December 31, 2014, 2013 or 2012.

16. COMMITMENTS AND CONTINGENCIES

Leases

The following shows the gross value and accumulated amortization of property, plant and equipment and mine development assets under capital leases related primarily to the leasing of mining equipment as of December 31:

	2014		2013
	(In thousands)
Gross value	$	74,203	$	24,982
Accumulated amortization	21,598		11,983

123

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Future minimum capital and operating lease payments as of December 31, 2014, are as follows:

	Capital Leases			Operating Leases
	(In thousands)
2015	$	41,927		$	16,886
2016	38,997			10,098
2017	28,273			6,554
2018	5,313			5,072
2019	2,346			4,231
Thereafter	198			3,942
Total minimum lease payments	117,054			$	46,783
Less imputed interest	(7,703		)
Present value of minimum capital lease payments	$	109,351

Rental expense under operating leases during the years ended December 31, 2014, 2013 and 2012 totaled $16.6 million, $11.8 million and $9.5 million, respectively.

The Company leases certain of its coal reserves from third parties and pays royalties based on either a per ton rate or as a percentage of revenues received. Royalties charged to expense under all such lease agreements amounted to $61.8 million, $43.6 million and $40.1 million in the years ended December 31, 2014, 2013 and 2012, respectively.

At December 31, 2014, the Company had fuel supply contracts outstanding with a minimum purchase requirement of 4.5 million gallons of diesel fuel per year. These contracts qualify for the normal purchase normal sale exception under hedge accounting.

Contingencies

The Company is a party to numerous claims and lawsuits with respect to various matters. The Company provides for costs related to contingencies when a loss is probable and the amount is reasonably estimable. After conferring with counsel, it is the opinion of management that the ultimate resolution of pending claims will not have a material adverse effect on the consolidated financial condition, results of operations, or liquidity of the Company.

17. BUSINESS SEGMENT INFORMATION

Segment information is based on a management approach, which requires segmentation based upon the Company’s internal organization, reporting of revenue, and operating income.

The Company’s operations are classified into six reporting segments: Coal - U.S., Coal - Canada, Coal - WMLP, Power, Heritage and Corporate. The Coal - U.S. reporting segment includes the aggregated operations of coal mines located in Wyoming, Montana, North Dakota and Texas. The Coal - Canada reporting segment includes the aggregated operations of coal mines located in Alberta and Saskatchewan. The Coal - WMLP reporting segment includes the operations of the Company's ownership in the general partner and majority interest in Westmoreland Resource Partners, LP, a publicly-traded coal master limited partnership. The Power segment includes its ROVA operations located in North Carolina. The Heritage segment costs primarily include benefits the Company provides to former mining operation employees as well as other administrative costs associated with providing those benefits and cost containment efforts. The Corporate segment primarily consists of corporate administrative expenses.

124

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

Summarized financial information by segment is as follows:

	Coal - U.S.		Coal - Canada(1)			Coal - WMLP(2)			Power			Heritage			Corporate			Consolidated
	(In thousands)
December 31, 2014
Revenues	$	642,075	$	388,664		$	—		$	85,253		$	—		$	—		$	1,115,992
Restructuring charges	1,058		9,565			2,783			459			78			1,046			14,989
Operating income (loss)	24,183		(2,670		)	(2,783		)	(35,023		)	(14,858		)	(11,824		)	(42,975		)
Depreciation, depletion, and amortization	54,563		36,068			—			9,998			—			149			100,778
Total assets	650,626		635,155			307,752			172,104			15,969			47,972			1,829,578
Capital expenditures	30,597		19,147			—			527			—			55			50,326
December 31, 2013
Revenues	$	587,119	$	—		$	—		$	87,567		$	—		$	—		$	674,686
Restructuring charges	—		—			—			5,078			—			—			5,078
Operating income (loss)	44,471		—			—			4,907			(14,498		)	(9,518		)	25,362
Depreciation, depletion, and amortization	56,698		—			—			10,179			—			354			67,231
Total assets	705,816		—			—			180,684			15,497			44,688			946,685
Capital expenditures	27,064		—			—			790			—			737			28,591
December 31, 2012
Revenues	$	519,152	$	—		$	—		$	81,285		$	—		$	—		$	600,437
Operating income (loss)	48,235		—			—			8,244			(14,711		)	(12,896		)	28,872
Depreciation, depletion, and amortization	46,639		—			—			10,085			—			421			57,145
Total assets	703,315		—			—			189,599			15,508			27,693			936,115
Capital expenditures	18,804		—			—			2,070			—			158			21,032

____________________

(1) The Canadian operations were acquired on April 28, 2014, therefore, information for the year ended December 31, 2014 includes approximately eight months of operations and there is no activity for 2013 and 2012.

(2) The operations reported under the segment Coal - WMLP were acquired on December 31, 2014, therefore, information for the year ended December 31, 2014 includes minimal operating activity and there is no activity for 2013 and 2012.

Certain amounts in prior periods have been reclassified to conform with the presentation of 2014. The reclassification affected depreciation, depletion and amortization and operating income (loss) between the Coal - U.S. segment and the Corporate segment.

During 2014, Westmoreland contributed certain royalty-bearing coal reserves from its Coal - U.S. segment to the Coal - WMLP segment. This contribution was recorded at the carrying amount as of the date of the contribution.

A reconciliation of segment income from operations to loss before income taxes follows:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Income (loss) from operations	$	(42,975	)	$	25,362		$	28,872
Loss on extinguishment of debt	(49,154		)	(64		)	(1,986		)
Interest expense	(84,234		)	(39,937		)	(42,677		)
Interest income	6,400			1,366			1,496
Loss on foreign exchange	(4,016		)	—			—
Other income	1,031			364			723
Loss before income taxes	$	(172,948	)	$	(12,909	)	$	(13,572	)

125

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

The Company derives its revenues from a few key customers. The customers from which more than 10% of total revenue has been derived and the percentage of total revenue from those customers is summarized as follows:

	December 31, 2014(2)			2013			2012
	(In thousands)
Customer A – Coal - Canada	$	144,863		$	—		$	—
Customer B – Coal - U.S.	128,104			117,545			126,982
Customer C – Coal - U.S	101,778			112,061			96,718
Customer D – Coal - U.S.	100,234			89,266			81,981
Customer E – Power	85,254			86,390			80,109
Customer F – Coal - U.S.	79,505			85,929			66,128
Customer G – Coal - U.S. (1)	44,234			25,958			26,525
Percentage of total revenue	61		%	77		%	80		%

____________________ 

(1) The revenue from Customer G did not exceed 10% in 2013 or 2012.

(2) The revenue from Customers B, C, D, E, F and G did not exceed 10% in 2014.

126

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT.)

18. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

	Three Months Ended
	March 31			June 30			September 30			December 31
	(In thousands; except per share data)
2014:
Revenues	$	180,202		$	287,956		$	337,830		$	310,004
Operating income (loss)	8,053			(29,640		)	(29,432		)	8,044
Net loss applicable to common shareholders	(19,291		)	(63,363		)	(49,329		)	(41,135		)
Basic loss per common share	$	(1.30	)	$	(4.19	)	$	(2.95	)	$	(2.41	)
2013:
Revenues	$	161,448		$	162,499		$	176,792		$	173,947
Operating income (loss)	5,734			11,975			8,536			(883		)
Net income (loss) applicable to common shareholders	(2,725		)	(622		)	2,421			(5,131		)
Basic income (loss) per common share	$	(0.19	)	$	(0.04	)	$	0.17		$	(0.35	)

During the fourth quarter of 2013, as a result of a review of useful lives assigned to assets under capital leases and an evaluation of other operating income, the Company recorded $1.5 million of additional net expense related to prior years. In accordance with applicable U.S. GAAP, management quantitatively and qualitatively evaluated the impact and determined it to be immaterial to the Company's 2013 consolidated financial statements.

The Canadian Acquisition was completed on April 28, 2014; therefore, operating results includes activities of the Canadian operations beginning with the three months ended June 30, 2014.

19. SUBSEQUENT EVENTS

Acquisition of Buckingham Coal Company, LLC

On January 1, 2015, Westmoreland completed the acquisition of Buckingham Coal Company, LLC, an Ohio-based coal supplier (“Buckingham”), pursuant to an agreement dated January 1, 2015 among WCC Land Holding Company, Inc. an affiliate of the Company for a total cash purchase price of $34.0 million, subject to customary post-closing adjustments. The cash purchase price was placed in escrow at December 31, 2014 and is included in Restricted investments and bond collateral in the accompanying consolidated balance sheet.

Separately, WCC Land Holding Company, Inc. entered into a five-year coal supply agreement with Buckingham’s primary customer, AEP Generation Resources Inc., which includes an obligation to purchase a minimum of 5.5 million tons of coal.

Add-on Term Loan Facility

On January 22, 2015, the Company amended the Term Loan Credit Agreement to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the Term Loan Credit Agreement were made in connection with the acquisition of Buckingham. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.

127

ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTINGAND FINANCIAL DISCLOSURE.

None.

ITEM 9A — CONTROLS AND PROCEDURES.

(a) Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Internal control over financial reporting refers to a process designed by, or under the supervision of, our principal executive and principal financial officers or persons performing similar functions, and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and our directors; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2014, using the framework set forth in the report of the Treadway Commission’s Committee of Sponsoring Organizations (2013 framework), ("COSO"), Internal Control — Integrated Framework. The scope of management’s assessment of the effectiveness of our internal control over financial reporting included all of our consolidated operations except for the operations of Westmoreland Resource Partners, LP (“WMLP”), in which we obtained a controlling interest on December 31, 2014. We have made this exclusion in reliance on the SEC’s guidance that an assessment of a recently acquired business may be omitted from the scope of our evaluation where it is not possible to conduct such an evaluation in the period between consummation of the acquisition and the date of management's assessment. WMLP represented approximately 17% and 0% of our total assets and total revenue, respectively, of the related consolidated financial statements amounts as of and for the year ended December 31, 2014. Based upon management’s evaluation, the Chief Executive Officer, ("CEO"), and Chief Financial Officer, ("CFO"), concluded that our internal control over financial reporting was effective as of December 31, 2014.

Our independent registered public accounting firm, Ernst & Young LLP, has issued an attestation report on our internal control over financial reporting as of December 31, 2014.

(b) Changes in Internal Control over Financial Reporting

On December 31, 2014, we closed on the WMLP Acquisition. As a result of the acquisition, we are in the process of

reviewing the internal controls of the WMLP operations and, if necessary, will make appropriate changes as we incorporate

our controls and procedures into the acquired operations. Except for the acquisition, there have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

(c) Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Westmoreland Coal Company and subsidiaries

We have audited Westmoreland Coal Company and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Westmoreland Coal Company and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

128

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Report on Internal Controls over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Westmoreland Resource Partners LP, which is included in the 2014 consolidated financial statements of Westmoreland Coal Company and subsidiaries and constituted 17% of total assets as of December 31, 2014 and 0% of total revenue for the year then ended. Our audit of internal control over financial reporting of Westmoreland Coal Company and subsidiaries also did not include an evaluation of the internal control over financial reporting of Westmoreland Resource Partners LP.

In our opinion, Westmoreland Coal Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Westmoreland Coal Company and subsidiaries’ as of December 31, 2014 and 2013 and the related consolidated statements of operations, comprehensive income (loss), shareholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2014, and our report dated March 6, 2015 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Denver, Colorado

March 6, 2015

(d) Evaluation of Disclosure Controls and Procedures

As of December 31, 2014, management conducted an evaluation, under the supervision and with the participation of our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as December 31, 2014 in ensuring that information required to be disclosed was recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

129

PART III

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required by Item 10 will be included under the headings Directors, Executive Officer, Corporate Governance and Section 16(a) Beneficial Ownership Reporting Compliance in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 19, 2015, and such required information is incorporated herein by reference.

ITEM 11 — EXECUTIVE COMPENSATION.

The information required by Item 11 will be included under the headings Corporate Governance, Director Compensation for 2014, Compensation Discussion and Analysis and Executive Compensation for 2014 in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 19, 2015, and such required information is incorporated herein by reference.

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The information required by Item 12 will be included under the headings Beneficial Ownership of Securities and Equity Compensation Plan Information in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 19, 2015, and such required information is incorporated herein by reference.

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

The information required by Item 13 will be included under the headings Certain Transactions and Corporate Governance in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 19, 2015, and such required information is incorporated herein by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information required by Item 14 will be included under the heading Auditors in our definitive proxy statement for our Annual Meeting of Stockholders to be held May 19, 2015, and such required information is incorporated herein by reference.

130

PART IV

ITEM 15 —EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

1. The following consolidated financial statements for Westmoreland Coal Company are filed herewith in Item 8:
	Report of Independent Registered Public Accounting Firm	77
	Report of Independent Registered Public Accounting Firm	78
	Consolidated Balance Sheets - December 31, 2014 and 2013	79
	Consolidated Statements of Operations - Years Ended December 31, 2014, 2013 and 2012	81
	Consolidated Statements of Comprehensive Income (Loss) - Years Ended December 31, 2014, 2013 and 2012	82
	Consolidated Statements of Shareholders’ Deficit - Years Ended December 31, 2014, 2013 and 2012	83
	Consolidated Statements of Cash Flows - Years Ended December 31, 2014, 2013 and 2012	84
	Notes to Consolidated Financial Statements	86
2. The following financial statement schedules are filed herewith:
	Schedule I — Condensed Financial Statements of Parent Company	133
3. The exhibits listed in the Exhibit Index are filed with or incorporated by reference in this Annual Report on Form 10-K.		141

131

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		WESTMORELAND COAL COMPANY
Date:	March 6, 2015	/s/ Keith E. Alessi
		Name: Keith E. Alessi
		Title:   Chief Executive Officer             (A Duly Authorized Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Keith E. Alessi	Chief Executive Officer	March 6, 2015
Keith E. Alessi	(Principal Executive Officer) and Director
/s/ Kevin A. Paprzycki	Chief Financial Officer and Treasurer	March 6, 2015
Kevin A. Paprzycki	(Principal Financial Officer)
/s/ Russell H. Werner	Controller (Principal Accounting Officer)	March 6, 2015
Russell H. Werner
/s/ Terry Bachynski	Director	March 6, 2015
Terry Bachynski
/s/ Gail E. Hamilton	Director	March 6, 2015
Gail E. Hamilton
/s/ Michael G. Hutchinson	Director	March 6, 2015
Michael G. Hutchinson
/s/ Richard M. Klingaman	Director	March 6, 2015
Richard M. Klingaman
/s/ Craig R. Mackus	Director	March 6, 2015
Craig R. Mackus
/s/ Jan B. Packwood	Director	March 6, 2015
Jan B. Packwood
/s/ Robert C. Scharp	Director	March 6, 2015
Robert C. Scharp

132

WESTMORELAND COAL COMPANY

SCHEDULE I — CONDENSED BALANCE SHEETS

(Parent Company Information — See Notes to Consolidated Financial Statements)

	December 31, 2014		December 31, 2013
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	697	$	25,326
Receivables:
Other	3,157		95
	3,157		95
Deferred income taxes	4,548		—
Other current assets	770		6,115
Total current assets	9,172		31,536
Property, plant and equipment:
Plant and equipment	4,079		3,939
Less accumulated depreciation, depletion and amortization	2,976		2,705
Net property, plant and equipment	1,103		1,234
Restricted investments and bond collateral	32,612		15,134
Investment in subsidiaries	373,562		266,847
Intercompany receivable/payable	215,401		—
Other assets	19,804		8,636
Total Assets	$	651,654	$	323,387

133

WESTMORELAND COAL COMPANY

SCHEDULE I — CONDENSED BALANCE SHEETS

(Parent Company Information — See Notes to Consolidated Financial Statements)

	December 31, 2014			December 31, 2013
	(In thousands)
Liabilities and Shareholders’ Deficit
Current liabilities:
Current installments of long-term debt	$	7,000		$	20,392
Revolving lines of credit	9,576			—
Accounts payable and accrued expenses:
Trade and other accrued liabilities	14,824			4,122
Interest payable	2,437			—
Workers’ compensation	671			717
Postretirement medical benefits	11,094			12,042
SERP	368			390
Intercompany receivable/payable	21,988			3,568
Other current liabilities	1,225			11,302
Total current liabilities	69,183			52,533
Long-term debt, less current installments	683,298			224,582
Workers’ compensation, less current portion	6,315			6,744
Excess of black lung benefit obligation over trust assets	11,252			8,675
Postretirement medical benefits, less current portion	186,376			185,858
Pension and SERP obligations, less current portion	25,178			13,069
Deferred income taxes	4,548			—
Other liabilities	626			5,939
Intercompany receivable/payable	14,323			13,866
Total liabilities	1,001,099			511,266
Shareholders’ deficit:
Preferred stock	92			160
Common stock	42,756			36,479
Other paid-in capital	185,644			134,861
Accumulated other comprehensive loss	(124,296		)	(63,595		)
Accumulated deficit	(468,902		)	(295,784		)
Total shareholders’ deficit	(364,706		)	(187,879		)
Noncontrolling interests in consolidated subsidiaries	15,261			—
Total deficit	(349,445		)	(187,879		)
Total Liabilities and Deficit	$	651,654		$	323,387

134

WESTMORELAND COAL COMPANY

SCHEDULE I — CONDENSED STATEMENTS OF OPERATIONS

(Parent Company Information — See Notes to Consolidated Financial Statements)

	Years Ended December 31,
	2014			2013			2012
	(In thousands, except per share data)
Revenues	$	—		$	—		$	—
Cost, expenses and other:
Cost of sales	(2,033		)	—			—
Depreciation, depletion and amortization	290			354			421
Selling and administrative	31,611			12,339			13,748
Heritage health benefit expenses	12,529			12,361			12,406
Loss on sales of assets	—			—			13
Restructuring charges	1,814			—			—
	44,211			25,054			26,588
Operating loss	(44,211		)	(25,054		)	(26,588		)
Other income (expense):
Interest expense	(73,612		)	(30,417		)	(31,301		)
Loss on extinguishment of debt	(34,947		)	(64		)	(1,986		)
Interest income	13,184			165			253
Loss on foreign exchange	(5,383		)	—			—
Other income	281			1			190
	(100,477		)	(30,315		)	(32,844		)
Loss before income taxes and income of consolidated subsidiaries	(144,688		)	(55,369		)	(59,432		)
Equity in income of subsidiaries	(28,298		)	42,347			45,762
Loss before income taxes	(172,986		)	(13,022		)	(13,670		)
Income tax expense (benefit)	194			(4,895		)	(8		)
Net loss	(173,180		)	(8,127		)	(13,662		)
Less net loss attributable to noncontrolling interest	(921		)	(3,430		)	(6,436		)
Net loss attributable to the Parent company	$	(172,259	)	$	(4,697	)	$	(7,226	)

135

WESTMORELAND COAL COMPANY

SCHEDULE I — COMPREHENSIVE INCOME (LOSS)

(Parent Company Information — See Notes to Consolidated Financial Statements)

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)
Other comprehensive income (loss)
Pension and other postretirement plans:
Amortization of accumulated actuarial gains or losses, pension	983			3,490			2,960
Adjustments to accumulated actuarial losses and transition obligations, pension	(24,793		)	28,974			(9,812		)
Amortization of accumulated actuarial gains or losses, transition obligations, and prior service costs, postretirement medical benefits	18			4,005			2,572
Adjustments to accumulated actuarial gains, postretirement medical benefits	(19,442		)	53,230			(22,342		)
Tax effect of other comprehensive income gains				(4,892		)	—
Change in foreign currency translation adjustment	(17,880		)	—			—
Unrealized and realized gains and losses on available-for-sale securities	413			(57		)	(268		)
Other comprehensive income (loss)	(60,701		)	84,750			(26,890		)
Comprehensive income (loss) attributable to Westmoreland Coal Company	$	(233,881	)	$	76,623		$	(40,552	)

136

WESTMORELAND COAL COMPANY

SCHEDULE I — CONDENSED STATEMENTS OF CASH FLOWS

(Parent Company Information — See Notes to Consolidated Financial Statements)

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Cash flows from operating activities:
Net loss	$	(173,180	)	$	(8,127	)	$	(13,662	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in income of subsidiaries	28,298			(42,347		)	(45,762		)
Depreciation, depletion and amortization	290			354			421
Non-cash tax benefits	—			(4,892		)	—
Share-based compensation	4,090			2,437			2,716
Loss on sales of assets	1			—			13
Amortization of deferred financing costs	959			3,165			2,889
Loss on extinguishment of debt	34,945			64			1,986
Gain on sales of investment securities	—			—			(190		)
Loss on foreign exchange	5,422			—			—
Changes in operating assets and liabilities:
Receivables	(1,541		)	(18		)	147
Excess of black lung benefit obligation over trust assets	2,577			319			1,791
Accounts payable and accrued expenses	(997		)	(613		)	4,981
Accrual for workers’ compensation	(475		)	(2,069		)	(2,096		)
Accrual for postretirement medical benefits	(2,192		)	101			(524		)
Pension and SERP obligations	(679		)	1,391			1,286
Other assets and liabilities	(11,389		)	(144		)	(243		)
Distributions received from subsidiaries	93,100			78,000			31,971
Net cash provided by (used in) operating activities	(20,771		)	27,621			(14,276		)
Cash flows from investing activities:
Additions to property, plant and equipment	(14		)	(737		)	(159		)
Change in restricted investments and bond collateral and reclamation deposits	16,469			49			(3,248		)
Cash payments in escrow for future acquisitions	(34,000		)	—			—
Cash payments related to acquisitions	(312,788		)	—			4,000
Proceeds from the sale of restricted investments	—			—			1,581
Net cash provided by (used in) investing activities	(330,333		)	(688		)	2,174
Cash flows from financing activities:
Borrowings from long-term debt, net of debt discount and premium	1,140,947			—			119,364
Repayments of long-term debt	(676,500		)	(500		)	(23,000		)
Borrowings on revolving lines of credit	9,576			—			—
Debt issuance costs and other refinancing costs	(67,697		)	(26		)	(5,666		)
Dividends/distributions	(859		)	(1,360		)	(1,360		)
Proceeds from issuance of common shares	56,474			—			—

137

Exercise of stock options	749			—			—
Transactions with Parent/affiliates	(136,215		)	(14,557		)	(88,541		)
Net cash provided by (used in) financing activities	326,475			(16,443		)	797
Effect of exchange rate changes on cash	—			—			—
Net increase (decrease) in cash and cash equivalents	(24,629		)	10,490			(11,305		)
Cash and cash equivalents, beginning of year	25,326			14,836			26,141
Cash and cash equivalents, end of year	$	697		$	25,326		$	14,836

138

WESTMORELAND COAL COMPANY

SCHEDULE I — NOTES TO FINANCIAL STATEMENTS

(Parent Company Information — See Notes to Consolidated Financial Statements)

1. LINES OF CREDIT AND LONG-TERM DEBT

The amounts outstanding under the Parent Company’s long-term debt consisted of the following as of the dates indicated:

	Total Debt Outstanding December 31,
	2014			2013
	(In thousands)
8.75% senior secured notes due 2021	$	350,000		$	—
Term loan facility due 2020	350,000			—
10.75% senior notes	—			251,500
Revolving line of credit	9,576			—
Other	3,500			—
Debt discount	(13,202		)	(8,525		)
Total debt outstanding	699,874			242,975
Less current installments	(16,576		)	—
Total debt outstanding, less current installments	$	683,298		$	242,975

The following table presents aggregate contractual debt maturities of all long-term debt for the Parent Company:

	As of December 31, 2014
	(In thousands)
2015	$	16,576
2016	3,500
2017	3,500
2018	3,500
2019	3,500
Thereafter	682,500
Total	713,076
Less: debt discount	(13,202		)
Total debt	$	699,874

8.75% Notes Offering

On December 16, 2014 (the “Closing Date”), the Company completed the issuance of $350.0 million in aggregate principal amount of 8.75% Notes. The 8.75% Notes were issued at a 1.292% discount, mature on January 1, 2022, and bear a fixed interest rate of 8.75% payable semiannually, on January 1 and July 1 of each year, commencing July 1, 2015. The 8.75% Notes are the Company’s senior secured obligations, rank equally in right of payment with all of the Company’s existing and future senior obligations, including the Term Loan Credit Facility Obligations defined below under “Term Loan Credit Agreement,” and rank senior to all of the Company’s existing and future indebtedness that is expressly subordinated to the 8.75% Notes. The 8.75% Notes have not been registered under the Securities Act of 1933. Proceeds from the 8.75% Notes offering and borrowing on the Term Loan Credit Agreement were used to repay the outstanding 10.75% senior notes with a principal balance of $675.5 million. As a result of the extinguishment of the 10.75% senior notes, the Company recorded a $34.9 million loss on extinguishment of debt. In 2014, the Company capitalized debt issuance costs of $10.2 million in connection with the 8.75% Notes.

The Company may redeem all or part of the 8.75% Notes beginning on January 1, 2018 at the redemption prices set forth in the Indenture, and prior to January 1, 2018 at 100% of the principal amount plus the applicable premium described in the Indenture. In addition, at any time prior to January 1, 2018, the Company may redeem up to 35% of the aggregate principal amount of the 8.75% Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.75% of the principal amount of the 8.75% Notes to be redeemed, together with accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

139

WESTMORELAND COAL COMPANY

SCHEDULE I — NOTES TO FINANCIAL STATEMENTS

(Parent Company Information — See Notes to Consolidated Financial Statements)

The 8.75% Notes are guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries). The 8.75% Notes are not guaranteed by Westmoreland Canada LLC or any of its subsidiaries, nor are they guaranteed by Westmoreland Resources GP, LLC or Westmoreland Resource Partners, LP, referred to as the Non-guarantors.

The 8.75% Notes and the guarantees are secured equally and ratably with the Term Loan Credit Agreement (i) by first priority liens on substantially all of the Company’s and the guarantor parties’ tangible and intangible assets (excluding certain equity interests, mineral rights and sales contracts and certain assets subject to existing liens) and (ii) subject to the Revolving Credit Agreement (as defined below), a second priority lien on substantially all cash, accounts and inventory of the Company and the guarantors, and any other property with respect to, evidencing or relating to such cash, accounts and inventory (whether now owned or hereinafter arising or acquired) and the proceeds and products thereof, subject in each case to permitted liens and certain exclusions (the “Notes Collateral”). The Notes Collateral is shared equally with the lenders under the Term Loan Credit Agreement, who hold identical first and second priority liens, as applicable, on the Notes Collateral.

The Indenture restricts the Company’s and its restricted subsidiaries’ ability to, among other things, (i) incur, assume or guarantee additional indebtedness or issue preferred stock; (ii) declare or pay dividends on, or make other distributions in respect of, their capital stock; (iii) purchase or redeem or otherwise acquire for value any capital stock or subordinated indebtedness; (iv) make investments, other than permitted investments; (v) create certain liens or use assets as security; (vi) enter into agreements restricting the ability of any restricted subsidiary to pay dividends, make loans, or any other distributions to the Company or other restricted subsidiaries; (vii) engage in transactions with affiliates; and (viii) consolidate or merge with or into other companies or transfer all or substantially all of their assets.

The Indenture contains, among other provisions, events of default and various affirmative and negative covenants. As of December 31, 2014, the Company was in compliance with all covenants for these Notes.

Term Loan Credit Agreement

Effective as of the Closing Date, the Company entered into a term loan credit agreement (the “Term Loan Credit Agreement”) which provides for a $350.0 million term loan facility (the “Term Loan”) with a single advance made on the Closing Date. The Term Loan was issued at a 2.5% discount and matures on December 16, 2020. Borrowings under the Term Loan will initially bear interest at one-month London Interbank Offered Rate (“LIBOR”) plus 6.50%. The interest rate at December 31, 2014 was 7.50%. In 2014, the Company capitalized debt issuance costs of $8.4 million in connection with the Term Loan.

The Term Loan Credit Agreement contains customary affirmative covenants, negative covenants, and events of default. Pursuant to the terms and provisions of the Guaranty and Collateral Agreement, dated the Closing Date, the obligations under the Term Loan are secured by identical first and second priority liens, as applicable, on the Notes Collateral. As of December 31, 2014, the Company was in compliance with all covenants for the Term Loan.

The Term Loan is guaranteed by Westmoreland Energy LLC, Westmoreland Kemmerer, Inc., Westmoreland Mining LLC, Westmoreland Resources, Inc. and certain other direct and indirect subsidiaries of the Company (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc., Westmoreland Canada, LLC, Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries).

Add-on Term Loan

On January 22, 2015, the Company amended the Term Loan Credit Agreement to increase the borrowings by $75.0 million, for an aggregate principal amount of $425.0 million. The amendments to the Term Loan Credit Agreement were made in connection with the acquisition of Buckingham Coal Company, LLC. Net proceeds were $71.0 million after a 2.5% discount, 1.5% broker fee, a consent fee of 1.17%, and $0.1 million of additional debt issuance costs.

Revolving Credit Agreement

During the first quarter of 2014, the Company amended its existing revolving credit agreement to increase the maximum available borrowing amount to $60.0 million. On December 16, 2014, the Company further amended the revolving credit agreement, or the Second Amended and Restated Loan Agreement, decreasing the maximum borrowing amount to $50.0 million in the aggregate, consisting of a $30.0 million sub-facility available in the U.S. and a $20.0 million sub-facility available in Canada. The maximum principal amount available for borrowings under the credit agreement can be increased to $100.0 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce

140

WESTMORELAND COAL COMPANY

SCHEDULE I — NOTES TO FINANCIAL STATEMENTS

(Parent Company Information — See Notes to Consolidated Financial Statements)

the balance available under the revolver. At December 31, 2014, availability on the revolver was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit. All extensions of credit under the revolver are collateralized by a first priority security interest in and lien upon the inventory and accounts receivable of substantially all of the Company's subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc.,Westmoreland Resources GP, LLC, Westmoreland Resource Partners, LP and certain other immaterial subsidiaries). Pursuant to the Intercreditor Agreement, the holders of the 8.75% Notes and the Term Loan have a subordinate lien on these assets. The revolver has a maturity date of December 31, 2018. The Company capitalized debt issuance costs of $0.7 million in 2014 related to the revolver amendments.

Borrowings under the Second Amended and Restated Loan Agreement initially bear interest either at a rate 0.75% in excess of the base rate (as detailed in the Second Amended and Restated Loan Agreement) or at a rate 2.75% per annum in excess of LIBOR, at the Borrowers’ election. An unused line fee of 0.50% per annum is payable monthly on the average unused amount of the revolver.

The loan agreement contains various affirmative, negative and financial covenants. Financial covenants in the agreement include a fixed charge coverage ratio and an EBITDA measure. The fixed charge coverage ratio must meet or exceed a specified minimum. The EBITDA covenant requires a minimum amount of EBITDA to be achieved. The Company met these covenant requirements as of December 31, 2014.

10.75% Senior Notes

On February 7, 2014, the Company closed on a private offering of $425.0 million in aggregate principal amount of 10.75% senior notes due 2018 at a price of 106.875% plus accrued interest from February 1, 2014. The private offering had the same terms as the then existing $251.5 million outstanding 10.75% Senior Notes. Total proceeds of the offering were $454.2 million, which included $29.2 million of debt premium. The net proceeds of the offering of the $425.0 million private offering were used to finance the $282.8 million initial cash payment for the Canadian Acquisition and cash transaction costs associated with the Canadian Acquisition and the private offering of approximately $24.0 million. The remaining balance of the proceeds were used to fund the prepayment of the WML Notes and for other general corporate purposes. The Company recorded $12.5 million of loss on extinguishment of debt for the year ended December 31, 2014 related to the payoff of the WML term debt. This loss included an $11.6 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs. In connection with the WML prepayment, the WML revolving credit facility was terminated.

On December 16, 2014, the Company used the proceeds from the 8.75% Senior Secured Notes and the Term Loan to pay the $675.5 million aggregate outstanding balance of the 10.75% senior notes. In connection with the repayment of the 10.75 Senior Notes, the Company recorded loss on extinguishment of $34.9 million for the year ended December 31, 2014. This loss included an $32.9 million make-whole payment with the remaining loss due to the write-off of unamortized debt issuance costs and unamortized debt premium.

EXHIBIT INDEX

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File Number	Exhibit	Filing Date	Filed Herewith
Other debt instruments are omitted in accordance with Item 601(b)(4)(iii)(A) of Regulation S-K. Copies of such agreements will be furnished to the Securities and Exchange Commission upon request. Exhibits with asterisks indicate management contracts or compensatory plans or arrangements.
3.1	Restated Certificate of Incorporation	S-1	333-117709	3.1	7/28/2004
3.2	Certificate of Correction to the Restated Certificate of Incorporation	8-K	001-11155	3.1	10/21/2004
3.3	Certificate of Amendment to the Restated Certificate of Incorporation	8-K	001-11155	3.1	9/7/2007
3.4	Certificate of Amendment to the Restated Certificate of Incorporation	8-K	001-11155	3.2	9/7/2007
3.5	Amended and Restated Bylaws	8-K	001-11155	3.1	2/20/2015
4.1	Certificate of Designation of Series A Convertible Exchangeable Preferred Stock	10-K	001-11155	3(a)	3/15/1993
4.2	Common Stock certificate	S-2	33-1950	4(c)	12/4/1985

141

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File Number	Exhibit	Filing Date	Filed Herewith
4.3	Preferred Stock certificate	S-2	33-47872	4.6	5/13/1992
4.4	Indenture, dated as of 2/04/2011, by and between Westmoreland Coal Company, Westmoreland Partners and Wells Fargo Bank, NA, as trustee and note collateral agent	8-K	001-11155	4.1	2/10/2011
4.5	Form of 10.75% Senior Notes due 2018 (included as Exhibit A in Exhibit 4.4)	8-K	001-11155	4.2	2/10/2011
4.6	Pledge and Security Agreement dated as of 2/04/2011, by Westmoreland Coal Company and Westmoreland Partners in favor of Wells Fargo Bank, NA, as note collateral agent	8-K	001-11155	4.4	2/10/2011
4.7	Supplemental Indenture, dated as of 1/31/2012, by and among Westmoreland Coal Company, Westmoreland Partners and Wells Fargo Bank, National Association, as trustee and note collateral agent	8-K	001-11155	4.1	1/31/2012
4.8	Form of 10.75% Senior Notes due 2018 (included as Exhibit A in Exhibit 4.9)	8-K	001-11155	4.1	1/31/2012
4.9	Amendment No. 1 to the Pledge and Security Agreement dated 1/26/2012	8-K	001-11155	4.4	1/31/2012
4.10	Indenture, dated as of 2/07/2014, by and between Escrow Corporation and Wells Fargo Bank, National Association, as trustee	8-K	001-11155	4.1	2/12/2014
4.11	Form of Escrow Note (included as Exhibit A within Exhibit 4.10 hereto)	8-K	001-11155	4.2	2/12/2014
4.12	Pledge and Security Agreement, dated as of 2/07/2014, by and between Escrow Corporation and Wells Fargo Bank, National Association	8-K	001-11155	4.3	2/12/2014
4.13	Second Supplemental Indenture, dated as of 2/03/2014, by and among Westmoreland Coal Company, Westmoreland Partners and Wells Fargo Bank, National Association, as trustee	8-K	001-11155	4.4	2/12/2014
4.14	Third Supplemental Indenture, dated as of 4/28/2014, by and among Westmoreland Coal Company, Westmoreland Partners, Wells Fargo Bank, National Association, as trustee and notes collateral agent and the guarantors party thereto	8-K	001-11155	10.2	5/2/2014
4.15	Fourth Supplemental Indenture, dated as of 4/28/2014, by and among Westmoreland Coal Company, Westmoreland Partners, Wells Fargo Bank, National Association,as trustee and notes collateral agent, and the guarantors party thereto	8-K	001-11155	10.3	5/2/2014
4.16	Fifth Supplemental Indenture, dated as of 7/31/2014, by and among Westmoreland Coal Company, Westmoreland Partners, Wells Fargo Bank, National Association, as trustee and notes collateral agent, and the guarantors party thereto	8-K	001-11155	10.1	8/6/2014

142

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File Number	Exhibit	Filing Date	Filed Herewith
4.17	Indenture, dated as of 12/16/2014, by and among Westmoreland Coal Company, the guarantors named therein, and U.S. Bank National Association, as trustee and notes collateral agent	8-K	001-11155	4.1	12/22/2014
4.18	Form of 8.75% Senior Notes due 2022	8-K	001-11144	4.2	12/22/2014
10.1*	Amended and Restated 2007 Equity Incentive Plan for Employees and Non-Employee Directors	10-K	001-11155	10.0	3/13/2012
10.2*	2014 Equity Incentive Plan	Schedule 14A	001-11155	Appen-dix A	3/26/2014
10.3*	Form of ISO Agreement	10-Q	001-11155	10.1	5/9/2008
10.4*	Form of NQSO Agreement for directors	10-Q	001-11155	10.2	5/9/2008
10.5*	Form of NQSO Agreement for persons other than directors	10-Q	001-11155	10.3	5/9/2008
10.6*	Form of Restricted Stock Unit Agreement for 2012 awards	10-Q	001-11155	10.2	8/9/2010
10.7*	Form of Performance-Based Restricted Stock Unit Agreement for 2012 awards	10-Q	001-11155	10.1	5/9/2011
10.8*	Form of Cash Time-Based Award for 2013	10-K	001-11155	10.10	3/13/2012
10.9*	Form of Cash Performance-Based Award for 2013	10-K	001-11155	10.11	3/13/2012
10.10*	Form of 2014 Equity Plan Time-Based Awards for Employees	10-Q	001-11155	10.2	7/31/2014
10.11*	Form of 2014 Equity Plan Performance-Based Awards for Employees	10-Q	001-11155	10.3	7/31/2014
10.12*	Form of 2014 Equity Plan Time-Based Awards for Directors	10-Q	001-11155	10.1	7/31/2014
10.13*	Severance Policy	10-Q	001-11155	10.9	8/5/2011
10.14*	Executive Transition Agreement effective 4/05/2013	10-Q	001-11155	10.1	11/8/2012
10.15	Amended Coal Mining Lease between Westmoreland Resources, Inc. (WRI) and Crow Tribe dated 11/26/1974, as amended in 1982	10-Q	0-752	10(a)	5/15/1992
10.16	Amendment to Amended Coal Mining Lease between the Crow Tribe and WRI dated 12/02/1994	10-K	001-11155	10.2	3/13/2009
10.17	Exploration and Option to Lease Agreement between the Crow Tribe and WRI dated 2/13/2004	10-K/A	001-11155	10.2	5/8/2009
10.18	Crow Tribal Lands Coal Lease between the Crow Tribe and WRI dated 2/13/2004	10-K/A	001-11155	10.5	5/8/2009
10.19	Master Agreement dated 1/04/1999, between Westmoreland Coal Company and the UMWA	8-K	001-11155	99.2	2/4/1999
10.20	Loan and Security Agreement dated as of 6/29/2012, by and among The PrivateBank and Trust Company, Westmoreland Coal Company and various subsidiaries	8-K	001-11155	10.1	7/3/2012

143

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File Number	Exhibit	Filing Date	Filed Herewith
10.21	First Amendment, dated as of 1/10/2014, and Second Amendment, dated as of 1/22/2014, to the Loan and Security Agreement dated as of 6/29/2012, by and among The PrivateBank and Trust Company, Westmoreland Coal Company and various subsidiaries	10-K	001-11155	10.38	2/28/2014
10.22	Tract 1 Lease dated 3/25/2013 between The Crow Tribe of Indians and Westmoreland Resources, Inc.	8-K	001-11155	10.1	3/27/2013
10.23	Consolidated Power Purchase and Operating Agreement dated 12/23/2013 for Roanoke Valley Units 1 and 2 by and between Westmoreland Partners and Virginia Electric and Power Company	10-K	001-11155	10.40	2/28/2014
10.24	Arrangement Agreement, dated as of 12/24/2013, by and among Westmoreland Coal Company, Sherritt International Corporation, Altius Minerals Corporation and other parties named therein	8-K	001-11155	99.5	1/23/2014
10.25	Purchase Agreement, dated as of 1/29/2014, by and among Westmoreland Escrow Corporation, BMO Capital Markets Corp. and Deutsche Bank Securities Inc.	8-K	001-11155	10.1	2/4/2014
10.26	Amending Agreement, dated as of 4/27/2014, by and among Westmoreland Coal Company, Sherritt International Corporation, Altius Minerals Corporation and other parties named therein	8-K	001-11155	10.1	5/2/2014
10.27	Registration Rights Agreement, dated as of 4/28/2014, by and among Westmoreland Coal Company, Westmoreland Partners, the guarantors party thereto and BMO Capital Markets Corp. and Deutsche Bank Securities Inc.	8-K	001-11155	10.4	5/2/2014
10.28	Amended and Restated Loan and Security Agreement, dated as of 4/28/2014, by and among Westmoreland Coal Company, certain of its subsidiaries, The PrivateBank and Trust Company, as administrative agent, and the lenders party thereto	8-K	001-11155	10.5	5/2/2014
10.29	Amended and Restated Intercreditor Agreement, dated as of 4/28/2014, by and among Wells Fargo Bank, National Association, as note collateral agent, and The PrivateBank and Trust Company, as administrative agent, as acknowledged and agreed to by Westmoreland Coal Company and certain of its subsidiaries	8-K	001-11155	10.6	5/2/2014
10.30	Agreement, dated as of 8/7/2014, by and between Cloud Peak Energy Logistics LLC and Coal Valley Resources, Inc.	8-K	001-11155	10.1	8/8/2014
10.31	Contribution Agreement, dated as of 10/16/2014, by and between Westmoreland Coal Company and Oxford Resource Partners, L.P.	10-Q	001-11155	10.6	10/28/2014

144

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	File Number	Exhibit	Filing Date	Filed Herewith
10.32	Purchase Agreement, dated as of 10/16/2014, by and among AIM Oxford Holdings, LLC, C&T Coal, Inc., Jeffrey M. Gutman, Daniel M. Maher, and the Warrantholders named therein, as sellers, and Westmoreland Coal Company, as buyer	10-Q	001-11155	10.7	10/28/2014
10.33	Credit Agreement, dated as of 12/16/2014, by and among Westmoreland Coal Company, the lenders from time to time party thereto, and Bank of Montreal, as administrative agent	8-K	001-11155	4.3	12/22/2014
10.34	Second Amended and Restated Loan and Security Agreement, dated as of 12/16/2014, by and among Westmoreland Coal Company, certain of its subsidiaries, The PrivateBank and Trust Company, as administrative agent, and the lenders party thereto	8-K	001-11155	4.4	12/22/2014
10.35	First Amendment to Credit Agreement, dated as of 1/22/2015, by and among Westmoreland Coal Company, the guarantors named therein, the lenders party thereto and Bank of Montreal, as administrative agent	8-K	001-11155	10.1	1/28/2015
10.36	Second Amendment to Credit Agreement, dated as of 1/22/2015, by and among Westmoreland Coal Company, the guarantors named therein, the lenders party thereto and Bank of Montreal, as administrative agent	8-K	001-11155	10.2	1/28/2015
21.1	Subsidiaries of Westmoreland Coal Company					X
23.1	Consent of Ernst & Young LLP					X
23.2	Consent of Grant Thornton LLP					X
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)					X
32	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350					X
95.1	Mine Safety Disclosure					X
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema Document					X
101.CAL	XBRL Taxonomy Calculation Linkbase Document					X
101.LAB	XBRL Taxonomy Label Linkbase Document					X
101.PRE	XBRL Taxonomy Presentation Linkbase Document					X
101.DEF	XBRL Taxonomy Definition Document					X

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related document is "unaudited" or "unreviewed."

145